UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the Fiscal Year Ended December 31, 20152017 OR |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the Transition Period from to |
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Commission File Number | | Registrant, State of Incorporation, Address and Telephone Number | | I.R.S. Employer Identification No. |
1-3526 | | The Southern Company | | 58-0690070 |
| | (A Delaware Corporation) | | |
| | 30 Ivan Allen Jr. Boulevard, N.W. | | |
| | Atlanta, Georgia 30308 | | |
| | (404) 506-5000 | | |
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1-3164 | | Alabama Power Company | | 63-0004250 |
| | (An Alabama Corporation) | | |
| | 600 North 18th Street | | |
| | Birmingham, Alabama 35291 | | |
| | (205) 257-1000 | | |
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1-6468 | | Georgia Power Company | | 58-0257110 |
| | (A Georgia Corporation) | | |
| | 241 Ralph McGill Boulevard, N.E. | | |
| | Atlanta, Georgia 30308 | | |
| | (404) 506-6526 | | |
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001-31737 | | Gulf Power Company | | 59-0276810 |
| | (A Florida Corporation) | | |
| | One Energy Place | | |
| | Pensacola, Florida 32520 | | |
| | (850) 444-6111 | | |
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001-11229 | | Mississippi Power Company | | 64-0205820 |
| | (A Mississippi Corporation) | | |
| | 2992 West Beach Boulevard | | |
| | Gulfport, Mississippi 39501 | | |
| | (228) 864-1211 | | |
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333-98553001-37803 | | Southern Power Company | | 58-2598670 |
| | (A Delaware Corporation) | | |
| | 30 Ivan Allen Jr. Boulevard, N.W. | | |
| | Atlanta, Georgia 30308 | | |
| | (404) 506-5000 | | |
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1-14174 | | Southern Company Gas | | 58-2210952 |
| | (A Georgia Corporation) | | |
| | Ten Peachtree Place, N.E. | | |
| | Atlanta, Georgia 30309 | | |
| | (404) 584-4000 | | |
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Securities registered pursuant to Section 12(b) of the Act:1(1)
Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is listed on the New York Stock Exchange.
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Title of each class | | | | Registrant |
Common Stock, $5 par value | | | | The Southern Company |
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Junior Subordinated Notes, $25 denominations | | | | |
6.25% Series 2015A due 2075 | | | | |
5.25% Series 2016A due 2076 | | | | |
5.25% Series 2017B due 2077 | | | | |
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Class A preferred stock, cumulative, $25 stated capital | | | | Alabama Power Company |
5.83%5.00% Series | | | | |
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Class A preferred stock, non-cumulative,
Par valueJunior Subordinated Notes, $25 per share denominations | | | | Georgia Power Company |
6 1/8%5.00% Series | | | | |
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Senior Notes | | | | Gulf Power Company |
5.75% Series 2011A 2017A due 2051 | | | | |
2077 | | | | |
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Depositary preferred shares, each representing one-fourth of a share of preferred stock, cumulative, $100 par value | | | | Mississippi Power Company |
5.25% Series | | | | |
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Senior Notes | | | | Southern Power Company |
1.000% Series 2016A due 2022 | | | | |
1.850% Series 2016B due 2026 | | | | |
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| | Securities registered pursuant to Section 12(g) of the Act:1(1) | | |
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Title of each class | | | | Registrant |
Preferred stock, cumulative, $100 par value | | | | Alabama Power Company |
4.20% Series 4.60% Series | | 4.72% Series | | |
4.52% Series 4.64% Series | | 4.92% Series | | |
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Preferred stock, cumulative, $100 par value | | | | Mississippi Power Company |
4.40% Series 4.60% Series | | | | |
4.72% Series | | | | |
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1(1) | As of December 31, 2015.2017. |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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Registrant | Yes | No |
The Southern Company | X | |
Alabama Power Company | X | |
Georgia Power Company | X | |
Gulf Power Company | | X |
Mississippi Power Company | | X |
Southern Power Company | X | |
Southern Company Gas | X | |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x (Response applicable to all registrants.)
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer"filer," "smaller reporting company," and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
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Registrant | Large Accelerated Filer | Accelerated Filer | Non-accelerated Filer | Smaller Reporting Company | Emerging Growth Company |
The Southern Company | X | | | | |
Alabama Power Company | | | X | | |
Georgia Power Company | | | X | | |
Gulf Power Company | | | X | | |
Mississippi Power Company | | | X | | |
Southern Power Company | | | X | | |
Southern Company Gas | | | X | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x (Response applicable to all registrants.)
Aggregate market value of The Southern Company's common stock held by non-affiliates of The Southern Company at June 30, 2015: $38.12017: $47.9 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant's common stock follows:
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Registrant | | Description of Common Stock | | Shares Outstanding at January 31, 2016 2018 |
The Southern Company | | Par Value $5 Per Share | | 912,846,9951,008,159,482 |
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Alabama Power Company | | Par Value $40 Per Share | | 30,537,500 |
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Georgia Power Company | | Without Par Value | | 9,261,500 |
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Gulf Power Company | | Without Par Value | | 5,642,7177,392,717 |
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Mississippi Power Company | | Without Par Value | | 1,121,000 |
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Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
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Southern Company Gas | | Par Value $0.01 Per Share | | 100 |
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Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 20162018 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Definitive Information Statements on Schedule 14C of Alabama Power Company Georgia Power Company, and Mississippi Power Company relating to each of their respective 20162018 Annual Meetings of Shareholders are incorporated by reference into PART III.
Each of Georgia Power Company, Gulf Power Company, Southern Power Company, and Southern Company Gas meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2)(b), (c), and (d) of Form 10-K.
This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Power Company.Company Gas. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.
Table of Contents
DEFINITIONS
When used in Items 1 through 5 and Items 9A through 15, the following terms will have the meanings indicated. |
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Term | Meaning |
AGL Resources | AGL Resources Inc. |
Alabama Power | Alabama Power Company |
Baseload ActBcf | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of MississippiBillion cubic feet |
Bridge AgreementCCR | Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CCR | Coal combustion residuals |
Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc. (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V. |
CO2 | Carbon dioxide |
CPCNCooperative Energy | Certificate of Public Convenience and Necessity |
CWIP | Construction WorkElectric cooperative in ProgressMississippi |
Dalton | City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
DOE | U.S. Department of Energy |
Duke Energy Florida | Duke Energy Florida, Inc.LLC |
EMC | Electric membership corporation |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FERC | Federal Energy Regulatory Commission |
FMPA | Florida Municipal Power Agency |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IBEW | International Brotherhood of Electrical Workers |
IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe) |
IIC | Intercompany Interchange Contract |
Internal Revenue Code | Internal Revenue Code of 1986, as amended |
IPP | Independent Power Producer |
IRP | Integrated Resource Plan |
ITC | Investment tax credit |
Kemper IGCC | IGCC facility under construction by Mississippi Power in Kemper County, Mississippi |
KUA | Kissimmee Utility Authority |
KW | Kilowatt |
KWH | Kilowatt-hour |
MATS rule | Mercury and Air Toxics Standards rule |
MEAG Power | Municipal Electric Authority of Georgia |
Merger | The merger, effective July 1, 2016, of Merger Suba wholly-owned, direct subsidiary of Southern Company with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement,Southern Company Gas, with AGL ResourcesSouthern Company Gas continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company |
Merger Agreement | Agreement and Plan of Merger, dated as of August 23, 2015, among Southern Company, AGL Resources, and Merger Sub |
Merger Sub | AMS Corp., a wholly-owned, direct subsidiary of Southern Company |
DEFINITIONS
(continued)
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Term | Meaning |
Mirror CWIP | A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers |
Mississippi Power | Mississippi Power Company |
MW | Megawatt |
natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light Company, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) |
Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
NRC | U.S. Nuclear Regulatory Commission |
NYSE | New York Stock Exchange |
OPC | Oglethorpe Power Corporation (an Electric Membership Corporation) |
OUC | Orlando Utilities Commission |
DEFINITIONS
(continued)
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Term | Meaning |
PATH Act | Protecting Americans from Tax Hikes Act |
Plant Vogtle Units 3 and 4 | Two new nuclear generating units under construction at Georgia Power's Plant Vogtle |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company(excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PowerSecure | PowerSecure Inc. |
PowerSouth | PowerSouth Energy Cooperative |
PPA | Power Purchase Agreementpurchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PSC | Public Service Commission |
registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company, and Southern Company Gas |
RUS | Rural Utilities Service |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
SEPA | Southeastern Power Administration |
SERC | Southeastern Electric Reliability Council |
SMEPA | South Mississippi Electric Power Association |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries |
Southern Holdings | Southern Company Holdings, Inc. |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
TIPATax Reform Legislation | The Tax Increase PreventionCuts and Jobs Act, of 2014which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
Virginia Natural Gas | Virginia Natural Gas, Inc. |
Vogtle Owners | Georgia Power, OPC, MEAG Power, and Dalton |
Westinghouse | Westinghouse Electric Company LLC |
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retailregulated rates, the potential financing of the Merger, the expected timing of the completion of the Merger, the strategic goals for the wholesale business, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan,plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources,completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, Internal Revenue Service and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and constructionoperation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company'sCompany system's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;actions;
actionslitigation related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating
to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;County energy facility;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas and the potential sale of a 33% equity interest in substantially all of Southern Power's solar assets, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and AGL ResourcesSouthern Company Gas will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;expected;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's subsidiarieselectric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the registrants from time to time with the SEC.
The registrants expressly disclaimsdisclaim any obligation to update any forward-looking statements.
PART I
Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern Company is registered and qualified to do business under the laws of Georgia and is qualified to do business as a foreign corporation under the laws of Alabama. Southern Company owns all of the outstanding common stock of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, each of which is an operating public utility company. The traditional electric operating companies supply electric service in the states of Alabama, Georgia, Florida, and Mississippi. More particular information relating to each of the traditional electric operating companies is as follows:
Alabama Power is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company, and Houston Power Company. The predecessor Alabama Power Company had been in continuous existence since its incorporation in 1906.
Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930 and was admitted to do business in Alabama on September 15, 1948 and in Florida on October 13, 1997.1930.
Gulf Power is a Florida corporation that has had a continuous existence since it was originally organized under the laws of the State of Maine on November 2, 1925. Gulf Power was admitted to do business in Florida on January 15, 1926, in Mississippi on October 25, 1976, and in Georgia on November 20, 1984. Gulf Power became a Florida corporation after being domesticated under the laws of the State of Florida on November 2, 2005.
Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972, was admitted to do business in Alabama on November 28, 1972 and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924 and was admitted to do business in Mississippi on December 23, 1924 and in Alabama on December 7, 1962.1924.
In addition, Southern Company owns all of the common stock of Southern Power Company, which is also an operating public utility company. Southern Power develops, constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power Company is a corporation organized under the laws of Delaware on January 8, 2001. Together withThe term "Southern Power" when used herein refers to Southern Power Company and its subsidiaries while the term "Southern Power Company" when used herein refers only to the parent company.
Southern PowerCompany Gas, which was acquired by Southern Company in July 2016, is admittedan energy services holding company whose primary business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland - through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to do businessthe distribution of natural gas. Southern Company Gas was incorporated under the laws of the State of Georgia on November 27, 1995 for the primary purpose of becoming the holding company for Atlanta Gas Light Company, which was founded in the States1856. See "The Southern Company System – Southern Company Gas" herein for additional information regarding agreements entered into by a wholly-owned subsidiary of Alabama, California, Florida, Georgia, Mississippi, Nevada, New Mexico, North Carolina, Oklahoma, South Carolina, and Texas.Southern Company Gas to sell two of its natural gas distribution utilities.
Southern Company also owns all of the outstanding common stock or membership interests of SouthernLINC Wireless,SCS, Southern Linc, Southern Holdings, Southern Nuclear, SCS, Southern Holdings,PowerSecure, and other direct and indirect subsidiaries. SouthernLINC WirelessSCS, the system service company, has contracted with Southern Company, each traditional electric operating company, Southern Power, Southern Company Gas, Southern Nuclear, SEGCO, and other subsidiaries to furnish, at direct or allocated cost and upon request, the following services: general executive and advisory, general and design engineering, operations, purchasing, accounting, finance and treasury, legal, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communication, and other services with respect to business and operations, construction management, and power pool transactions. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and also provides wholesale fiber optic solutions to telecommunication providers inoptics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and for other electric and natural gas products and services. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power'sthe Southern Company system's nuclear power plants and is currently managing construction of and developing Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power. SCSPowerSecure is a provider of products and services in the Southern Company system service company providing, at cost, specialized services to Southern Companyareas of distributed generation infrastructure, energy efficiency, and its subsidiary companies. Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and also for energy services.utility infrastructure.
Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,019,680 KWs1,020 MWs at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power and Georgia Power are each entitled to one-half of SEGCO's capacity and energy. Alabama Power acts as SEGCO's agent in the operation of SEGCO's units and furnishes fuel to SEGCO for its units. SEGCO also owns one 230,000 volt transmission line extending from Plant Gaston to the Georgia state line at which point connection is made with the Georgia Power transmission line system.
On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger, other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and any shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes. Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement. See Note 12 to the financial statements under "Southern Company – Proposed Merger with AGL Resources" in Item 8 herein for additional information regarding the Merger.
Segment information for Southern Company's segment informationCompany and Southern Company Gas is included in Note 13 to the financial statements of Southern Company and Note 12 to the financial statements of Southern Company Gas in Item 8 herein.
The registrants' Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and allany amendments to those reports are made available on Southern Company's website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company's internet address is www.southerncompany.com.
The Southern Company System
Traditional Electric Operating Companies
The traditional electric operating companies are vertically integrated utilities that own generation, transmission, and distribution facilities. See PROPERTIES in Item 2 herein for additional information on the traditional electric operating companies' generating facilities. Each company's transmission facilities are connected to the respective company's own generating plants and other sources of power (including certain generating plants owned by Southern Power) and are interconnected with the transmission facilities of the other traditional electric operating companies and SEGCO. For information on the State of Georgia's integrated transmission system, see "Territory Served by the Southern Company System – Traditional Electric Operating Companies and Southern Power" herein.
Agreements in effect with principal neighboring utility systems provide for capacity and energy transactions that may be entered into from time to time for reasons related to reliability or economics. Additionally, the traditional electric operating companies have entered into voluntary reliability agreements with the subsidiaries of Entergy Corporation, Florida Electric Power Coordinating Group, and Tennessee Valley Authority and with Duke Energy Progress, Inc.,LLC, Duke Energy Carolinas, LLC, South Carolina Electric & Gas Company, and Virginia Electric and Power Company, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The traditional electric operating companies have joined with other utilities in the Southeast (including some of those referred to above) to form the SERC to augment further the reliability and adequacy of bulk power supply. Through the SERC, the traditional electric operating companies are represented on the National Electric Reliability Council.
The utility assets of the traditional electric operating companies and certain utility assets of Southern Power Company are operated as a single integrated electric system, or power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional electric operating companies and Southern Power Company. The fundamental purpose of the power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional electric operating company and Southern Power Company retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the power pool for use in serving customers of other traditional electric operating companies or Southern Power Company or for sale by the power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from power pool transactions with third parties.
Southern Company, each traditional operating company, Southern Power, Southern Nuclear, SEGCO, and other subsidiaries have contracted with SCS to furnish, at direct or allocated cost and upon request, the following services: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communication, and other services with respect to business and operations, construction management, and power pool transactions. Southern Power and SouthernLINC WirelessSouthern Linc have also secured from the traditional electric operating companies certain services which are furnished at cost and, in the case of Southern Power, which are subject tocompliance with FERC regulations.
Alabama Power and Georgia Power each have a contractagreements with Southern Nuclear to operate the Southern Company system's existing nuclear plants, Plants Farley, Hatch, and Vogtle. In addition, Georgia Power has a contractan agreement with Southern Nuclear to develop, license, construct, and operate Plant Vogtle Units 3 and 4. See "Regulation – Nuclear Regulation" herein for additional information.
Southern Power
The term "Southern Power" when used herein refers to Southern Power Company and its subsidiaries while the term "Southern Power Company" when used herein refers only to the parent company. Southern Powerdevelops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects,facilities, and sells electricity at market-based rates (under authority from the FERC) in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, development and construction of new power plants,generating facilities, and
entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load serving entities.load-serving entities, as well as commercial and industrial customers. Southern Power's business activities are not subject to traditional state regulation like the traditional electric operating companies, but the majority of its business activities are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by generally making such risks the responsibility of the counterparties to its PPAs. However, Southern Power's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as Southern Power’sPower's ability to execute its growth strategy and to develop and construct generating facilities. For additional information on Southern Power's business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" of Southern Power in Item 7 herein.
Southern Power Company directly owns and manages generation assets primarily in the Southeast, which are included in the power pool, and has other wholly-ownedvarious subsidiaries, two of which are Southern Renewable Energy, Inc. (SRE) and Southern Renewable Partnerships, LLC (SRP), which were created to own and operate natural gas and renewable projectsgeneration facilities either wholly or in partnership with various third parties, such as Turner Renewable Energy, LLC (TRE), First Solar Inc. (First Solar), or Recurrent Energy, a subsidiaryparties. As of Canadian Solar Inc. (Recurrent), which are not includedDecember 31, 2017, Southern Power's generation fleet totaled 12,940 MWs of nameplate capacity in the power pool.commercial operation (including 5,152 MWs owned by its subsidiaries). In addition, Southern Power Company has other subsidiaries either with natural gas and biomass generating facilities orthat are pursuing additional natural gas generation and other development opportunities. The generation assets of Southern Power Company's subsidiaries are not included in the power pool.
Since 2010, SRESome of Southern Power's partnerships allow for the sharing of cash distributions and TRE, throughtax benefits at differing percentages. Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by SRE, has acquired all of the outstanding membership interests of eight solar projects that own the following solar photovoltaic facilities: Adobe, Apex, Campo Verde, Cimarron, Granville, Macho Springs, Morelos, and Spectrum. In December 2015, STR entered into a purchase agreement with Solar Frontier Americas Holding LLC, the developer of the Calipatria solar project, to acquire all of the outstanding membership interests of Calipatria Solar, LLC (Calipatria), which closed on February 11, 2016. Additionally, in December 2015, SRE acquired 100% of all the outstanding membership interests of Kay Wind, LLC, which owns and operates the Kay Wind facility. In September 2015, SRE entered into a purchase agreement with Apex Clean Energy Holdings, LLC, the developer of the Grant Wind project, to acquire all of the outstanding membership interests of Grant Wind, LLC (Grant Wind), which is expected to close in March 2016 when the project reaches commercial operation.
In 2014 and 2015, SRP acquired 100% of the outstanding class A membership interests of seven partnership entities that own the following solar photovoltaic facilities: Desert Stateline (which is being completed in eight phases), Garland, Imperial Valley, Lost Hills Blackwell, North Star, Roserock, and Tranquillity. Imperial Valley was placed in service in 2014; Lost Hills Blackwell, North Star, and three of the eight phases of Desert Stateline were placed in service in 2015; and phases four and five of Desert Stateline were placed in service in January and February 2016, respectively. Garland, Roserock, Tranquillity, and the remaining three phases of Desert Stateline are expected to be placed in service later in 2016. SRPPower is entitled to 51% of all cash distributions from eight of the partnership entities and the respective partner who holds the class B membership interests (either First Solar or Recurrent) is entitled to 49% of all cash distributions. For the Desert Stateline partnership, Southern Power is entitled to 66% of all cash distributions and the class B member is entitled to 34% of all cash distributions. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the seventhese nine partnership entities.
In December 2014,September 2017, Southern Power announcedbegan a legal entity reorganization of various direct and indirect subsidiaries that it will build an approximately 146-MW solar photovoltaic facility, Sandhills, in Taylor County, Georgia. During the first half of 2015, Southern Power Company acquiredown and operate substantially all of the outstanding membership interests of five entities that were subsequently mergedsolar facilities, including certain subsidiaries owned in partnership with Southern Power Company for the construction of five solar photovoltaic facilities in Georgia as follows: Decatur County, Decatur Parkway, Butler, Butler Solar Farm, and Pawpaw. Decatur County and Decatur Parkway were placed in service in late 2015; Butler Solar Farm was placed in service in February 2016; and Pawpaw, Sandhills, and Butler arevarious third parties. The reorganization is expected to be placed in service during 2016.
The entire output of each of the renewable facilities is contracted under long-term PPAs as shown belowsubstantially completed in the tablefirst quarter 2018. Southern Power is pursuing the sale of PPAs asa 33% equity interest in the newly-formed holding company owning these solar assets, which, if successful, is expected to close in the middle of December 31, 2015. 2018. The ultimate outcome of this matter cannot be determined at this time.
See PROPERTIES in Item 2 – Properties,herein, Note 211 to the financial statements of Southern Power in Item 8 herein, and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 herein for additional information regarding Southern Power's acquisitions, construction, and constructiondevelopment projects.
As of December 31, 2015, Southern Power had 9,595 MWscalculates an investment coverage ratio for its generating assets based on the ratio of nameplate capacity in commercial operation (including 2,110 MWs owned by its subsidiaries), after taking into consideration its equity ownership percentage ofinvestment under contract to total investment using the solar facilities.respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. With the inclusion of the PPAs and capacityinvestments associated with the solarwind and natural-gas fired facilities currently under construction and the acquisitions of Calipatria and Grant Wind, all as discussed above,Gaskell West 1 solar project, which was acquired subsequent to December 31, 2017, as well as other capacity and energy contracts, Southern Power has an average investment coverage ratio of 75% of its available demonstrated capacity covered for the next five years (through 2020)91% through 2022 and 89% through 2027, with an average remaining contract duration of 70% of its available demonstrated capacity covered for the next 10 years (through 2025).approximately 15 years.
Southern Power’sPower's natural gas and biomass sales are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block
sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serveserves the customer’scustomer's capacity and energy requirements from a combination of the customer’scustomer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers’customers' resources when economically viable. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operations and maintenance costs based on dollars-per-kilowatt year and to provide a return on investment.
Southern Power’sPower's electricity sales from solar and wind salesgenerating facilities are alsopredominantly through long-term PPAs; however, these solar and wind PPAs but do not have a capacity charge. Instead thecharge and customers either purchase the entire energy output of a dedicated renewable facility through an energy charge.charge or provide Southern Power a certain fixed price for the electricity sold
to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
The following tables set forth Southern Power’s existingPower's PPAs as of December 31, 2015:2017:
Block Sales PPAs
|
| | | | | | | | | |
Facility/Source | | Counterparty | | MWs(1) |
| | | | Contract Term |
Addison UnitUnits 1 | | MEAG Power | | 152 |
| | | | through April 2029 |
Addison Units 2 and 43 | | Georgia Power | | 293297 |
| | | | through May 2030 |
Addison Unit 32 | | MEAG Power | | 149 |
| | | | through April 2029 |
Addison Unit 4 | | Georgia Energy Cooperative | | 151146 |
| | | | through May 2030 |
Cleveland County Unit 1 | | NCEMC(1)North Carolina Electric Membership Corporation (NCEMC) | | 45-180 |
| | | | through Dec. 2036 |
Cleveland County Unit 2 | | NCEMC(1)NCEMC | | 180183 |
| | | | through Dec. 2036 |
Cleveland County Unit 3 | | NCMPA1(2)North Carolina Municipal Power Agency 1 | | 183 |
| | | | through Dec. 2031 |
Cleveland County Unit 4 | | PJM Interconnection LLC(2) | | 183 |
| | | | June 2020 – May 2021 |
Dahlberg Units 1, 3, and 5 | | Cobb EMC | | 224 |
| | | | Jan. 2016 –through Dec. 20252026 |
Dahlberg Units 2, 6, 8, and 10 | | Georgia Power | | 298 |
| | | | through May 2025 |
Dahlberg Unit 4 | | Georgia Power | | 7374 |
| | | | through May 2030 |
Franklin Unit 1 | | Duke Energy Florida Inc. | | 350 |
| | | | through May 2016 |
Franklin Unit 1 | | Duke Energy Florida, Inc. | | 434 |
| | | | June 2016 –through May 2021 |
Franklin Unit 2 | | Morgan Stanley Capital Group | | 250 |
| | | | Jan. 2016 –through Dec. 2025 |
Franklin Unit 2 | | Jackson EMC | | 60-65 |
| | | | Jan. 2016 –through Dec. 2035 |
Franklin Unit 2 | | GreyStone Power Corporation | | 35-40 |
| | | | Jan. 2016 –through Dec. 2035 |
Franklin Unit 2 | | Cobb EMC | | 100 |
| | | | Jan. 2016 –through Dec. 20252026 |
Franklin Unit 3 | | Exelon Generation Company LLCMorgan Stanley Capital Group | | 100200 |
| | | | Jan. 2016 -through Dec. 20162027 |
Franklin Unit 3 | | Cargill Power Markets LLCCity of Dalton, Georgia | | 5070 |
| | | | Jan. 2016 -through Dec. 20162027 |
Harris Unit 1 | | Georgia Power | | 638628 |
| | | | through May 2030 |
Harris Unit 2 | | Georgia Power | | 631657 |
| | | | through May 2019 |
Harris Unit 2 | | AMEA(3)Alabama Municipal Electric Authority(3) | | 25 |
| | | | Jan. 2020 – Dec. 2025 |
Mankato | | Northern States Power Company | | 375 |
| | | | through June 2026 |
Mankato | | Northern States Power Company | | 345 |
| | | | June 2019 – May 2039(4) |
Nacogdoches | | City of Austin, Texas | | 100 |
| | | | through May 2032 |
NCEMC PPA(4)PPA(5) | | EnergyUnited | | 100 |
| | | | through Dec. 2021 |
Oleander Units 2, 3, and 4 | | Seminole Electric Cooperative | | 155466 |
| | | | through MayDec. 2021 |
Oleander Unit 5 | | FMPA | | 157 |
| | | | through Dec. 2027 |
Rowan CT Unit 1 | | NCMPA1(2)North Carolina Municipal Power Agency 1 | | 150 |
| | | | through Dec. 2030 |
Rowan CT Unit 2 | | PJM Interconnection LLC(2) | | 154 |
| | | | June 2020 – May 2021 |
Rowan CT Units 2 and 3 | | EnergyUnited | | 100-175 |
| | | | Jan. 2022 – Dec. 2025 |
Rowan CT Unit 3 | | EnergyUnited | | 113 |
| | | | through Dec. 2023 |
Rowan CC Unit 4 | | EnergyUnited | | 0-32823-328 |
| | | | through Dec. 2025 |
Block Sales PPAs (continued)
|
| | | | | | | | | |
Facility/Source | | Counterparty | | MWs(1) |
| | | | Contract Term |
Rowan CC Unit 4 | | Duke Energy Progress, Inc.LLC | | 150 |
| | | | through Dec. 2019 |
Rowan CC Unit 4 | | PJM Auction(5)Century Aluminum(6) | | 200158 |
| | | | June 2016 – May 2017through Dec. 2018 |
Stanton Unit A | | OUC | | 341342 |
| | | | through Sept. 2033 |
Stanton Unit A | | FMPA | | 85 |
| | | | through Sept. 2033 |
Wansley Unit 67 | | Georgia PowerJacksonville Electric Authority | | 570200 |
| | | | through May 2017Dec. 2019 |
| |
(1) | North Carolina Electric Membership Corporation (NCEMC)The MWs and related facility units may change due to unit rating changes or assignment of units to contracts. |
| |
(2) | North Carolina Municipal Power Agency 1 (NCMPA1)Amount sold into PJM capacity market. |
| |
(3) | Alabama Municipal Electric Authority (AMEA). AMEA will also be served by Plant Franklin Unit 1 from January 2018 through December 2019. |
| |
(4) | Subject to commercial operation of the 345-MW expansion project. |
| |
(5) | Represents sale of power purchased from NCEMC under a PPA. |
| |
(5)(6) | Pennsylvania, Jersey, Maryland Power PoolCentury Aluminum PPA is partially served by Plant Franklin Unit 3. |
Requirements Services PPAs
|
| | | | | | | |
Counterparty | | MWs(1) | |
| | Contract Term |
Nine Georgia EMCs | | 223-456294-376 |
| | (1) | | through Dec. 2024 |
Sawnee EMC | | 116-559267-639 |
| | (1) | | through Dec. 2027 |
Cobb EMC | | 0-3160-170 |
| | (1) | | Jan. 2016 -through Dec. 20252026 |
Flint EMC | | 128-257136-360 |
| | (1) | | through Dec. 2024 |
City of Dalton, Georgia | | —92 |
| | (1) | | through Dec. 20172027 |
EnergyUnited | | 0-21978-159 |
| | (1) | | through Dec. 2025 |
City of Blountstown, Florida | | 10 |
| | through April 2022 |
| |
(1) | Represents a range of forecasted incremental capacity needs over the contract term. |
Solar/Wind PPAs
|
| | | | |
Facility | Counterparty | MWs(1)MWs(1) |
| Contract Term |
Solar | | | |
Adobe(2)Adobe | Southern California Edison Company | 20 |
| through MayJune 2034 |
Apex(2)Apex | Nevada Power Company | 20 |
| through Dec. 2037 |
Boulder 1(2) | Nevada Power Company | 100 |
| through Dec. 2036 |
Butler | Georgia Power | 100 | Dec. 2016 -
| through Dec. 2046 (5) |
Butler Solar Farm | Georgia Power | 20 | Jan. 2016 - Dec. 2035
| through Feb. 2036 |
Calipatria(2)Calipatria | San Diego Gas & Electric Company | 20 |
| through Feb. 2016 - Jan. 2036 |
Campo Verde(2)Verde | San Diego Gas & Electric Company | 139 |
| through Sept.Oct. 2033 |
Cimarron(2)Cimarron | Tri-State Generation and Transmission Association, Inc. | 30 |
| through Nov.Dec. 2035 |
Decatur County | Georgia Power | 19 |
| through Dec. 2035 |
Decatur Parkway | Georgia Power | 80 |
| through Dec. 2040 |
Desert Stateline(4)Stateline(2) | Southern California Edison Company | 300 | Sep. 2016 - Oct.
| through Sept. 2036 (5) |
Garland(4)East Pecos | Austin Energy | 119 |
| through April 2032 |
Garland A(2) | Southern California Edison Company | 20 | Dec. 2016 - Nov.
| through Sept. 2036 (5) |
Garland(4)Garland(2) | Southern California Edison Company | 180 | Dec. 2016 - Nov.
| through Oct. 2031 (5) |
Granville(2)Granville | Duke Energy Progress, Inc.LLC | 2.52 |
| through Nov.Oct. 2032 |
Henrietta(2) | Pacific Gas & Electric Company | 100 |
| through Sept. 2036 |
Imperial Valley(4)Valley(2) | San Diego Gas & Electric Company | 150 |
| through Dec.Nov. 2039 |
Lost Hills Blackwell(4) | City of Roseville & Pacific Gas & Electric Company | 32 | through Dec. 2043 |
Macho Springs(2) | El Paso Energy | 50 | through May 2034 |
Morelos(2) | Pacific Gas & Electric Company | 15 | Jan. 2016 - Jan. 2035 |
North Star(4) | Pacific Gas & Electric Company | 60 | through May 2035 |
Pawpaw | Georgia Power | 30 | Mar. 2016 - Feb. 2046 (5) |
Roserock(4) | Austin Energy | 157 | Oct. 2016 - Sept. 2036 (5) |
Sandhills | Cobb EMC | 111 | Nov. 2016 - Dec. 2041 (5) |
Sandhills | Flint EMC | 15 | Nov. 2016 - Dec. 2041 (5) |
Sandhills | Sawnee EMC | 15 | Nov. 2016 - Dec. 2041 (5) |
Sandhills | Middle GA and Irwin EMC | 2 | Nov. 2016 - Dec. 2041 (5) |
Spectrum(2) | Nevada Power Company | 30 | through Dec. 2038 |
Tranquillity(4) | Shell Energy North America (US), LP | 204 | Oct. 2016 - Nov. 2019 (5) |
Tranquillity(4) | Southern California Edison Company | 204 | Dec. 2019 - Nov. 2034 (5) |
Solar/Wind PPAs (continued)
|
| | | | |
Facility | Counterparty | MWs(1)MWs(1) |
| Contract Term |
Lamesa | City of Garland, Texas | 102 |
| through April 2032 |
Lost Hills Blackwell(2) | City of Roseville, California & Pacific Gas & Electric Company | 32 |
| through Dec. 2043 |
Macho Springs | El Paso Electric Company | 50 |
| through May 2034 |
Morelos | Pacific Gas & Electric Company | 15 |
| through Feb. 2036 |
North Star(2) | Pacific Gas & Electric Company | 60 |
| through June 2035 |
Pawpaw | Georgia Power | 30 |
| through March 2046 |
Roserock(2) | Austin Energy | 157 |
| through Nov. 2036 |
Rutherford | Duke Energy Carolinas, LLC | 75 |
| through Dec. 2031 |
Sandhills | Cobb EMC | 111 |
| through Oct. 2041 |
Sandhills | Flint EMC | 15 |
| through Oct. 2041 |
Sandhills | Sawnee EMC | 15 |
| through Oct. 2041 |
Sandhills | Middle Georgia and Irwin EMC | 2 |
| through Oct. 2041 |
Spectrum | Nevada Power Company | 30 |
| through Dec. 2038 |
Tranquillity(2) | Shell Energy North America (US), LP | 204 |
| through Nov. 2019 |
Tranquillity(2) | Southern California Edison Company | 204 |
| Dec. 2019 – Nov. 2034 |
Wind | | | |
Bethel | Google Inc. | 225 |
| through Jan. 2029 |
Cactus Flats(3) | General Mills, Inc. | 98 |
| Aug. 2018 – July 2034 |
Cactus Flats(3) | General Motors Company | 50 |
| Aug. 2018 – July 2031 |
Grant Wind(3)Plains | Oklahoma Municipal Power Authority | 41 |
| Jan. 2020 – Dec. 2039 |
Grant Plains | Steelcase Inc. | 25 |
| through Dec. 2028 |
Grant Plains | Allianz Risk Transfer (Bermuda) Ltd. | 81-122 |
| through March 2027 |
Grant Wind | East Texas Electric Cooperative | 50 | Mar. 2016 - Mar.
| through March 2036 (5) |
Grant Wind(3)Wind | Northeast Texas Electric Cooperative | 50 | Mar. 2016 - Mar.
| through March 2036 (5) |
Grant Wind(3)Wind | Western Farmers Electric Cooperative | 50 | Mar. 2016 - Mar.
| through March 2036 (5) |
Kay Wind | Westar Energy Inc. | 199200 | Oct. 2016 - Nov. 2036
| through Dec. 2035 |
Kay Wind | Grand River Dam Authority | 10099 |
| through Dec. 2035 |
Passadumkeag | Western Massachusetts Electric Company | 40 |
| through June 2031 |
Salt Fork Wind | City of Garland, Texas | 150 |
| through Nov. 2030 |
Salt Fork Wind | Salesforce.com, Inc. | 24 |
| through Nov. 2028 |
Tyler Bluff Wind | The Proctor & Gamble Company | 96 |
| through Dec. 2028 |
Wake Wind(2) | Equinix Enterprises, Inc. | 100 |
| through Oct. 2028 |
Wake Wind(2) | Owens Corning | 125 |
| through Oct. 2028 |
________________________
(1) MWs shown are for 100% of the PPA.PPA, which is based on demonstrated capacity of the facility.
(2) Southern Power's equity interest in these facilitiesFacility is 90%.
(3)the subject of a partnership where Southern Power has entered into an agreement to acquire this facility, which is subject to satisfaction of certain conditions to closing.the majority member. See PROPERTIES in Item 2 herein for additional information.
(4) Southern Power's equity interest in these facilities is 51%.
(5)(3) Subject to commercial operation.
Purchased Power
|
| | | | |
Facility/Source | Counterparty | MWs |
| Contract Term |
NCEMC | NCEMC | 100 |
| through Dec. 2021 |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" and "Acquisitions" of Southern Power in Item 7 herein and Note 211 to the financial statements of Southern Power in Item 8 herein for additional information.
For the year ended December 31, 2015,2017, approximately 11.3% of Southern Power's revenues were derived approximately 15.8% from Georgia Power and approximately 10.7% from Florida Power & Light Company.Power. Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power’sPower's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power’sPower's earnings but is not expected to have a material impact on Southern Company's earnings.
Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas marketing services, wholesale gas services, and gas midstream operations.
Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains 82,000 miles of natural gas pipelines and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.6 million customers across seven states and has rates of return that are regulated by each individual state in return for exclusive franchises.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings Inc., entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey Board of Public Utilities, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey Board of Public Utilities and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.
Gas marketing services is comprised of SouthStar Energy Services, LLC (SouthStar) and Nicor Energy Services Company (doing business as Pivotal Home Solutions) and provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice. SouthStar, serving approximately 774,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management. Pivotal Home Solutions, serving approximately 1.2 million service contracts, provides a suite of home protection products and services that offers homeowners predictability regarding their energy service delivery, systems, and appliances.
Wholesale gas services consists of Sequent Energy Management, L.P. and engages in natural gas storage and gas pipeline arbitrage and provides natural gas asset management and related logistical services to most of the natural gas distribution utilities as well as non-affiliate companies.
Gas midstream operations includes joint ventures in pipeline investments (including a 50% ownership interest in Southern Natural Gas Company, L.L.C. and two significant pipeline construction projects) as well as a 50% joint ownership in a significant pipeline project and wholly-owned natural gas storage facilities that enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Southern Natural Gas Company, L.L.C. is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.
For additional information on Southern Company Gas' business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Other Businesses
PowerSecure, which was acquired by Southern Company in May 2016, provides products and services in the areas of distributed energy infrastructure, energy efficiency, and utility infrastructure.
Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and also for energyother electric and natural gas products and services.
SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public. SouthernLINC WirelessSouthern Linc delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. SouthernLINC WirelessSouthern Linc also provides fiber cableoptics services within the Southeast through its subsidiary, Southern Telecom, Inc.
These efforts to invest in and develop new business opportunities may offer potential returns exceeding those of rate-regulated operations. However, these activities alsooften involve a higher degree of risk.
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 20162018 through 2018,2022, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company, each traditional electric operating company, Southern Power, and Southern PowerCompany Gas in Item 7 herein. The Southern Company system's construction program consists of capital investment and capital expenditures to comply with environmental statuteslaws and regulations. The Southern Company systemtraditional electric operating companies also anticipates costsanticipate expenditures associated with ash pond closure in place or by other methods and ground water monitoring of ash ponds in accordance withunder the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures below as these costs are associated withSouthern Company system's asset retirement obligation liabilities. In 2016,2018, the construction program is expected to be apportioned approximately as follows:
|
| | | | | | | | | | | | | | | |
| Southern Company system(a) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power |
| (in millions) |
New Generation | $ | 1,224 |
| $ | 56 |
| $ | 553 |
| $ | 3 |
| $ | 612 |
|
Environmental Compliance(b) | 683 |
| 319 |
| 313 |
| 30 |
| 21 |
|
Generation Maintenance | 978 |
| 293 |
| 538 |
| 75 |
| 72 |
|
Transmission | 618 |
| 167 |
| 402 |
| 23 |
| 26 |
|
Distribution | 802 |
| 285 |
| 417 |
| 62 |
| 37 |
|
Nuclear Fuel | 230 |
| 93 |
| 137 |
| — |
| — |
|
General Plant | 307 |
| 93 |
| 174 |
| 22 |
| 19 |
|
| 4,842 |
| 1,306 |
| 2,534 |
| 215 |
| 787 |
|
Southern Power(c) | 2,386 |
| | | | |
Other subsidiaries | 102 |
| | | | |
Total | $ | 7,330 |
| $ | 1,306 |
| $ | 2,534 |
| $ | 215 |
| $ | 787 |
|
|
| | | | | | | | | | | | | | | |
| Southern Company system(a)(b) | Alabama Power | Georgia Power(a) | Gulf Power | Mississippi Power |
| (in billions) |
New generation | $ | 1.3 |
| $ | — |
| $ | 1.3 |
| $ | — |
| $ | — |
|
Environmental compliance(c) | 1.1 |
| 0.6 |
| 0.5 |
| 0.1 |
| — |
|
Generation maintenance | 0.9 |
| 0.5 |
| 0.2 |
| 0.1 |
| 0.1 |
|
Transmission | 0.9 |
| 0.3 |
| 0.5 |
| — |
| — |
|
Distribution | 1.2 |
| 0.5 |
| 0.5 |
| 0.1 |
| 0.1 |
|
Nuclear fuel | 0.3 |
| 0.1 |
| 0.2 |
| — |
| — |
|
General plant | 0.5 |
| 0.2 |
| 0.2 |
| — |
| — |
|
| 6.0 |
| 2.2 |
| 3.3 |
| 0.3 |
| 0.2 |
|
Southern Power(d) | 1.3 |
| | | | |
Southern Company Gas(e) | 1.7 |
| | | | |
Other subsidiaries | 0.4 |
| | | | |
Total(a) | $ | 9.4 |
| $ | 2.2 |
| $ | 3.3 |
| $ | 0.3 |
| $ | 0.2 |
|
|
| |
(a) | These amounts include the amounts forTotals may not add due to rounding. |
| |
(b) | Includes the traditional electric operating companies, (as detailed in the table above)Southern Power, and Southern Company Gas, as well as the amounts for Southern Power and the other subsidiaries. See "Other Businesses" herein for additional information. |
(b) | |
(c) | Reflects cost estimates for environmental regulations. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA’s final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units or costs associated with closure in place or by other methods and ground watergroundwater monitoring of ash ponds in accordance withunder the CCR Rule. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information. |
(c) | |
(d) | Includes approximately $0.8$0.9 billion for potentialplanned expenditures for plant acquisitions and/or constructionand placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. |
| |
(e) | Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Infrastructure Replacement Programs and Capital Projects" of new generating facilities.Southern Company Gas in Item 7 herein for additional information. See |
"The Southern Company System – Southern Company Gas" herein for additional information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. Projected capital expenditures of $0.1 billion related to these two natural gas distribution utilities are excluded from the amounts above.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; PSCstate regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been finalized or previously constructed, including first-of-a-kind technology, which may result in revised estimates during construction. The abilitySee Note 3 to control coststhe financial statements of Southern Company and avoid cost overruns during the developmentGeorgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for additional information regarding Georgia Power's construction of new facilities is subject to a number of factors, including, but not limited to, changes in labor costsPlant Vogtle Units 3 and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC).4.
SeeAlso see "Regulation – Environmental StatutesLaws and Regulations" herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Jointly-Owned"Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Facilities" in Item 2 herein for additional information concerning Alabama Power's, Georgia Power's, and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities. See Note 3 to the financial statements ofutilities and Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for additional information regarding Georgia Power’s constructionGas' joint ownership of Plant Vogtle Units 3 and 4. Also see Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 herein for additional information regarding Mississippi Power’s construction of the Kemper IGCC.a pipeline facility.
Financing Programs
See each of the registrant's MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.
Fuel Supply
Electric
The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Electricity Business – Fuel and Purchased Power Expenses" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Fuel and Purchased Power Expenses" of each traditional electric operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 20132015 through 2015.2017.
The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2018 coal burn requirements in 2016.requirements. These agreements have terms ranging between one and fivefour years. In 2015,2017, the weighted average sulfur content of all coal burned by the traditional electric operating companies was 0.95% sulfur.1.12%. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional electric operating companies to remain within limits set by Phase I of the Cross-State Air Pollution Rule (CSAPR) under the Clean Air Act. In 2015,2017, the Southern Company system did not purchase any sulfur dioxide allowances, annual nitrogen oxide emission allowances, or seasonal nitrogen oxide emission allowances from the market. As any additional environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure that the traditional electric operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each traditional electric operating company, and Southern Power in Item 7 herein for additional information on environmental matters.
SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2016,2018, SCS has contracted for 457 billion cubic feet510 Bcf of natural gas supply under agreements with remaining terms up to 15 years. In addition to natural gas supply, SCS has contracts in place
for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.
Alabama Power and Georgia Power have numerousmultiple contracts covering a portion of their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. TheseThe uranium, conversion services, and fuel fabrication contracts haveare for terms of less than 10 years with varying expiration dates and most of themdates. The term lengths for the enrichment services contracts are for less than 10 years.15 years with varying expiration dates. Management believes suppliers have sufficient capacity for nuclear fuel supplies and processing existsproduction capability to precludepermit the impairment of normal operationsoperation of the Southern Company system's nuclear generating units.
Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's PPAs (excluding solarnatural gas and wind)biomass PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.
Natural Gas
Recent advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and relatively low prices for natural gas. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the state regulatory agencies in which Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and from its wholly-owned subsidiary, Sequent Energy Management, L.P., under asset management agreements in states where such agreements are approved by the applicable state regulatory agency. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.
Territory Served by the Southern Company System
Traditional Electric Operating Companies and Southern Power
The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2015,2017, the territory had an area of approximately 120,000 square miles and an estimated population of approximately 17 million. Southern Power sells electricity at market-based rates in the wholesale market, primarily to investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load serving entities.load-serving entities, as well as commercial and industrial customers.
Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the transmission, distribution, and sale of such electricity,electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 14 municipally-owned electric
distribution systems, 11 of which are served indirectly through sales to AMEA,the Alabama Municipal Electric Authority, and two rural distributing cooperative associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances.appliances and products and markets and sells outdoor lighting services.
Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the transmission, distribution, and sale of such electricityelectric service within the State of Georgia, at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale currently to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation, transmission, distribution, and purchase of electricity and the transmission, distribution, and sale of such electricity,electric service, at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility.
Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the transmission, distribution, and sale of such electricityelectric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of each traditional electric operating company in Item 7 herein. For information relating to the number of retail customers served by customer classification for the traditional electric operating companies, see SELECTED FINANCIAL DATA of each traditional electric operating company in Item 6 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, reference is made to Item 7 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. As of December 31, 2015,2017, there were 71approximately 62 electric cooperative organizationsdistribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. As of December 31, 2015,2017, PowerSouth owned generating units with approximately 2,100 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. PowerSouth's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for details of Alabama Power's joint-ownership with PowerSouth of a portion of Plant Miller. Alabama Power has a 15-year system supply agreement with PowerSouth to provide 200 MWs of capacity service through December 31, 2030 with an option to extend and renegotiate in the event Alabama Power builds new generation or contracts for new capacity.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territories of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.
OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets and power purchased from other suppliers.
Four electric cooperative associations, financed by the RUS, operate within Gulf Power's service territory. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power's service territory and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with SMEPA,Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided.
As of December 31, 2015,2017, there were approximately 6572 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
As of December 31, 2015,2017, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Southern Power assumed or entered into PPAs with some of the traditional electric operating companies, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load serving entities.load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" above and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 herein for additional information concerning Southern Power's PPAs.
SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.
Southern Company Gas
Southern Company Gas is engaged in the distribution of natural gas in seven states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2017 are as follows:
|
| | | | | |
Utility | State | Number of customers |
| Approximate miles of pipe |
|
| | (in thousands) | |
Nicor Gas | Illinois | 2,228 |
| 34,300 |
|
Atlanta Gas Light Company | Georgia | 1,622 |
| 33,500 |
|
Virginia Natural Gas | Virginia | 299 |
| 5,600 |
|
Elizabethtown Gas(*) | New Jersey | 292 |
| 3,200 |
|
Florida City Gas | Florida | 109 |
| 3,700 |
|
Chattanooga Gas Company | Tennessee | 66 |
| 1,600 |
|
Elkton Gas(*) | Maryland | 7 |
| 100 |
|
Total | | 4,623 |
| 82,000 |
|
| |
(*) | For information relating to the pending asset sales of Elizabethtown Gas and Elkton Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Merger, Acquisition, and Disposition Activities" of Southern Company Gas in Item 7 herein and Note 11 to the financial statements of Southern Company Gas under "Proposed Sale of Elizabethtown Gas and Elkton Gas" in Item 8 herein. |
For information relating to the sources of revenue for Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Competition
Electric
The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992, which allowed IPPs to access a utility's transmission network in order to sell electricity to other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may without further certification, extend or maintain its lines upelectric
system subject to certain regulatory approvals; extensions within that areaof facilities by such utility, or extensions of facilities into that area by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate that are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors.
Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales primarily in the Southeasternacross various U.S. wholesale market.utility markets. The needs of this marketthese markets are driven by the demands of end users in the Southeast and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.
As of December 31, 2015,2017, Alabama Power had cogeneration contracts in effect with nineeight industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2015,2017, Alabama Power purchased approximately 20198 million KWHs from such companies at a cost of $4$3 million.
As of December 31, 2015,2017, Georgia Power had contracts in effect with 2427 small power producers whereby Georgia Power purchases their excess generation. During 2015,2017, Georgia Power purchased 804 million1.6 billion KWHs from such companies at a cost of $60$114 million. Georgia Power also has PPAs for electricity with sixfour cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2015,2017, Georgia Power purchased 28526 million KWHs at a cost of $25$0.7 million from these facilities.
Also during 2015,2017, Georgia Power purchased energy from three customer-owned generating facilities. These customers provide only energy to Georgia Power, and make no capacity commitment, and are not dispatched by Georgia Power. During 2015,2017, Georgia Power purchased a total of 34317 million KWHs from the three customers at a cost of approximately $1$25 million.
As of December 31, 2015,2017, Gulf Power had agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases "as available" energy from customer-owned generation. During 2015,2017, Gulf Power purchased 211277 million KWHs from such companies for approximately $6$7 million.
As of December 31, 2015,2017, Mississippi Power had onea cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2015,2017, Mississippi Power did not purchase any excess generation from this customer.
Natural Gas
Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.
Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.
Customer demand for natural gas could be affected by numerous factors, including:
changes in the availability or price of natural gas and other forms of energy;
general economic conditions;
energy conservation, including state-supported energy efficiency programs;
legislation and regulations;
the cost and capability to convert from natural gas to alternative energy products; and
technological changes resulting in displacement or replacement of natural gas appliances.
The natural gas-related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.
The availability and affordability of natural gas have provided cost advantages and further opportunity for growth of the businesses.
Seasonality
The demand for electric power generationand natural gas supply is affected by seasonal differences in the weather. AtIn most of the areas the traditional electric operating companies and Southern Power, the demand forserve, electric power peaks eithersales peak during the summer orwith a smaller peak during the winter, months, with market prices reflectingwhile in most of the areas Southern Company Gas serves, natural gas demand of power and available generating resources at that time.peaks during the winter. As a result, the overall operating results of Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas have historically sold less power and natural gas when weather conditions are milder.
Regulation
State Commissions
The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs. The PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Traditional Operating Companies and Southern Power"Company System" and "Rate Matters" herein for additional information.
Federal Power Act
The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2015,2017, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,667,0001,670,000 KWs and 1817 existing Georgia Power generating stations having anand one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1,087,296 KWs.
In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. The Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission have also filed petitions for rehearing of the FERC order. In April 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. The order also denied all of the other rehearing requests. In May 2016, Alabama Rivers Alliance and American Rivers filed a second rehearing request and, in June 2016, also filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit for review of the license and the rehearing denial order. The FERC issued an order in September 2016 denying the second rehearing request, and American Rivers and Alabama Rivers Alliance subsequently filed an appeal of that order at the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit consolidated the two appeals into one proceeding.
In 2013,2017, Alabama Power filedcontinued the process of developing an application to relicense the Harris Dam project on the Tallapoosa River, which is expected to be filed with the FERC to relicense the Holt hydroelectric project located on the Warrior River.by November 30, 2021. The current Holt license expired on August 31, 2015. Since the FERC did not act on Alabama Power's new license application prior to the expiration of the existing license, the FERC issued to Alabama Power an annual license authorizing continued operation of the project under the terms and conditions of the expired license until action is taken on the new license.
On December 17, 2015, the FERC issued a new 30-year license to Alabama Power for the MartinHarris Dam project locatedlicense will expire on the Tallapoosa River. The Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission have filed petitions for rehearing of the FERC order.November 30, 2023.
In 2015,2017, Georgia Power initiatedcontinued the process of developing an application to relicense the Wallace Dam project on the Oconee River. The current Wallace Dam project license will expire on June 1, 2020. Georgia Power's hydro electric licenses expiring in 2023 include the Lloyd Shoals project, the Riverview project, and the Langdale project. The FERC relicensing proceedings for these three projects are expected to begin in 2018.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 KW capacity. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Licenses for all projects, excluding those discussed above, expire in the years 2023-20352023-2066 in the case of Alabama Power's projects and in the years 2020-20442035-2044 in the case of Georgia Power's projects.
Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another,
the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.
The ultimate outcome of these matters cannot be determined at this time.
Nuclear Regulation
Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978;1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1 and 2 expire in 2047 and 2049, respectively.
In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear"Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for additional information.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
Environmental StatutesLaws and Regulations
The electric utilities'Southern Company system's operations are subject to extensive regulationregulated by state and federal environmental agencies underthrough a variety of statuteslaws and regulations governing environmental media, including air, water, land, and landprotection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. For Southern Company Gas, substantially all of these costs are related to former manufactured gas plants sites, which are primarily recovered through existing ratemaking provisions. See Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 herein for additional information.
Compliance with federal environmental statuteslaws and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional electric operating company, Southern Power, SEGCO, and SEGCO. In addition, existingSouthern Company Gas. New or revised environmental laws and regulations may be changed or new lawscould affect many areas of the traditional electric operating companies', Southern Power's, and regulations may be adopted or otherwise become applicable to the Southern Company system, including laws and regulations designed to address air quality, water, CCRs, global climate change, or other environmental and health concerns, as well as wildlife and endangered species conservation.natural gas distribution utilities' operations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein for additional information about environmental issues, including, but not limited to, proposed and final regulations related to air quality, water quality, CCRs, and greenhouse gases. Also seeglobal climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 herein for additional information about environmental issues and global climate change regulation.issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 herein for additional information about environmental remediation liabilities.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations; the time periods over which compliance with regulations is required; individual statedepend on various factors, such as state-level adoption and implementation of regulations, as applicable;requirements, the availability and cost of any deployed control technology, and the outcome of anypending and/or future legal challenges to the environmental rules and any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology and costs; and the fuel mix of the electric utilities.challenges. Compliance costs may ariseresult from existing unit retirements,the installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units.units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates
companies or market-based rates for Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity,energy, which could negatively affect results of operations, cash flows, and financial condition. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each of the traditional operating companies, and Southern Power in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Southern Company system. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities' operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the electric utilities' commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.electricity and natural gas. See "Construction Program" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each of the traditional electric operating companies, Southern Power, and Southern Company Gas in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
Rate Matters
Rate Structure and Cost Recovery Plans
Electric
The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.
The traditional electric operating companies recover their respectivecertain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved environmental compliance, storm damage, and certain other costs are recovered at Alabama Power, Gulf Power, and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power and Gulf Power through periodic base rate proceedings.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company and each of the traditional electric operating companies under "Retail Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also, see Note 1 to the financial statements of Southern Company and each of the traditional electric operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and environmental compliance costs through rate mechanisms.
See "Integrated Resource Planning" herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources and decertification of existing supply-side resources for Georgia Power. In addition, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear"Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover financing costs for construction of Plant Vogtle Units 3 and 4 during the construction period beginning in 2011.
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle"Kemper County Energy Facility – Rate Recovery of Kemper IGCC Costs"Recovery" of Mississippi Power in Item 7 herein for information on cost recovery plans with respect to the Kemper IGCC.County energy facility.
The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of each of the registrants in Item 7 herein for information on the traditional electric operating companies' and Southern Power Company's market-based rate authority and a pending FERC proceedingproceedings relating to this authority.
Through 2015, capacity revenues represented the majority of Gulf Power's wholesale earnings. Gulf Power had long-term sales contracts to cover 100% of its ownership share of Plant Scherer Unit 3 (205 MWs) and these capacity revenues represented 82% of total wholesale capacity revenues for 2015. Due to the expiration of a wholesale contract at the end of 2015 and future expiration dates of the remaining wholesale contracts for the unit, Gulf Power currently has contracts to cover 34% of the unit for 2016 and 27% of the unit through 2019. Although Gulf Power is actively evaluating alternatives relating to this asset, including replacement wholesale contracts, the expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years. In the event some portion of Gulf Power's ownership of Plant Scherer Unit 3 is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.
Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalitiesa municipality located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.0%19.3% of Mississippi Power's operating revenues in 20152017 and are largely subject to rolling 10-year10-
year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Natural Gas
Southern Company Gas' seven natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies with respect to rates charged to their customers, maintenance of accounting records, and various service and safety matters. Rates charged to these customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide each natural gas distribution utility the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt, and provide a reasonable return. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
With the exception of Atlanta Gas Light Company, which operates in a deregulated environment in which gas marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas.
The natural gas distribution utilities, excluding Atlanta Gas Light Company, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing natural gas for their customers. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Utility Regulation and Rate Design" of Southern Company Gas in Item 7 herein and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.
Integrated Resource Planning
Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See "Environmental StatutesLaws and Regulations" above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies.
Certain of the traditional electric operating companies periodicallyare required to file IRPs with their respective state PSC as discussed below.
Georgia Power
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electricalelectric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Rate Plans,Plans" and " "–– Integrated Resource Plan,"Plan" and "– Nuclear"Nuclear Construction" and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans," "– Integrated Resource Plan," and "– Nuclear Construction" in Item 8 herein for additional information.
Gulf Power
Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power's estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state's electric utilities are reviewed by the Florida PSC and subsequently classified as either "suitable" or "unsuitable." The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical power plant site certification proceedings. Under
Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC.
Gulf Power's most recent 10-year site plan was classified by the Florida PSC as "suitable" in November 2015. Gulf Power's most recent 10-year site2017. The plan and environmental compliance plan identifyidentifies environmental regulations and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Air Quality," "– Environmental StatutesLaws and Regulations – Coal Combustion Residuals," and "– Global Climate Issues" of Gulf Power in Item 7 herein. Gulf Power continues to evaluate the economics of various potential planning scenarios for units at certain Gulf Power coal-fired generating plants as EPA and other regulations develop.
On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016, asAs a result of the cost to comply with environmental regulations imposed by the EPA. In connection with this retirement,EPA, Gulf Power reclassified the net carrying value of these units from plantretired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) in service, net of depreciation, to other utility plant, net. The net book value of these units at December 31, 2015 was approximately $62 million. Subsequent to December 31, 2015, Gulf Power filed a petition withMarch 2016. In August 2016, the Florida PSC requesting permissionapproved Gulf Power's request to create a regulatory asset forreclassify the
remaining net book value of Plant Smith Units 1 and 2 and the remaining inventorymaterials and supplies associated with these units as of the retirement date. The retirement of these units is not expecteddate, totaling approximately $63 million, to have a material impact on Gulf Power's financial statements asregulatory asset. Gulf Power expects to recover these amounts through its rates; however,began amortizing the ultimate outcome depends on futureinvestment balances over 15 years effective January 1, 2018 as determined in a rate proceedings withcase settlement agreement approved by the Florida PSC and cannot be determined at this time.on April 4, 2017.
Mississippi Power
Mississippi Power's 2010 IRP indicated that, among other things, Mississippi Power plansplanned to construct the Kemper County energy facility as an IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Air Quality" and "– Global Climate Issues" of Mississippi Power in Item 7 herein. In August 2014,
On February 6, 2018, the Mississippi Power entered intoPSC approved a settlement agreement with the Sierra Club that, among other things, required the Sierra Clubrelated to dismiss or withdraw all pending legal and regulatory challenges tocost recovery for the Kemper IGCC and the flue gas desulfurization system project at Plant Daniel Units 1 and 2,County energy facility, pursuant to which also occurred in August 2014. In addition, and consistent with Mississippi Power’s ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than Decemberfile a Reserve Margin Plan (RMP) by August 2018. The RMP will include many of the same aspects of a traditional IRP, but the RMP will also contain alternatives proposed by Mississippi Power also agreed that it would cease burning coal or other solid fuelto address its current capacity which is in excess of Mississippi Power's long-term targeted reserve margin. The ultimate outcome of this matter cannot be determined at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred on April 16, 2015), and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016.this time.
For additional information regarding Mississippi Power's construction of the Kemper IGCC,County energy facility, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" in Item 8 herein.
The ultimate outcome of these matters cannot be determined at this time.
Employee Relations
The Southern Company system had a total of 26,70331,344 employees on its payroll at December 31, 2015.2017.
|
| | |
| Employees at December 31, 20152017 |
Alabama Power | 6,613 |
|
Georgia Power | 6,986 |
|
Georgia Power | 7,989 |
|
Gulf Power | 1,3911,288 |
|
Mississippi Power | 1,4781,242 |
|
PowerSecure | 1,448 |
|
SCS | 4,6093,740 |
|
Southern Company Gas | 5,318 |
|
Southern Nuclear | 4,0123,936 |
|
Southern Power*Power | 0541 |
|
Other | 238232 |
|
Total | 26,70331,344 |
|
|
| |
* | Southern Power has no employees. Southern Power has agreements with SCS and the traditional operating companies whereby employee services are rendered at amounts in compliance with FERC regulations. |
The traditional electric operating companies and the natural gas distribution utilities have separate agreements with local unions of the IBEW and the Utilities Workers Union of America generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.
Alabama Power has agreements with the IBEW in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2016.2021.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through April 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through May 1, 2019. In 2013,2015, Mississippi Power signed a separate agreement with the IBEW related solely to the Kemper IGCC, whichCounty energy facility; that current agreement is in effect through March 15, 2021. In August 2017, Mississippi Power signed an agreement with the IBEW that added several job classifications and provided guidelines related to the reorganization at the Kemper County energy facility.
Southern Nuclear has ana five-year agreement with the IBEW covering certain employees at Plants Hatch and Plant Vogtle Units 1 and 2, which is in effect through June 30, 2016.2021. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley is in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.
The natural gas distribution utilities have separate agreements with local unions of the IBEW and Utilities Workers Union of America covering wages, working conditions, and procedures for handling grievances and arbitration. Nicor Gas' agreement with the IBEW is effective through February 29, 2020. Virginia Natural Gas' agreement with the IBEW is effective through May 16, 2020. Elizabethtown Gas' agreement with the Utility Workers Union of America is effective through November 21, 2019. The agreements also make the terms of the Southern Company Gas pension plan subject to collective bargaining with the unions when significant changes to the benefit accruals are considered by Southern Company Gas.
Effective in December 2017, 538 employees transferred from SCS to Southern Power. Southern Power became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including accumulated other comprehensive income impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, Southern Power's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations.
Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, including MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.
UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS
Southern Company and its subsidiaries are subject to substantial state and federal governmental regulation. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Power,Company Gas, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses, including ratesbusinesses. Jointly-owned facilities may be subject to regulation by governmental agencies of more than one state and charges, service regulations, retail service territories, sales of securities, incurrence of indebtedness, asset acquisitions and sales, accounting and taxthose state's governmental agencies may have different policies and practices, physical security and cyber-security policies and practices,with respect to such jointly-owned facilities. The traditional electric operating companies and the construction and operation of fossil-fuel, nuclear, hydroelectric, solar, wind, and biomass generating facilities, as well as transmission andnatural gas distribution facilities. For example, the respective state PSCs must approve the traditional operating companies' requested rates for retail customers. The traditional operating companiesutilities seek to recover their costs (including a reasonable return on invested capital) through their retail rates, and there canwhich must be no assurance that aapproved by the applicable state PSC or other applicable state regulatory agency. A state PSC or other applicable state regulatory agency, in a future rate proceeding, will notmay alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and by Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments must be approved by the FERC. These wholesale rates could be affected by changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority. The FERC rules related to retaining the authority to sell electricity at market-based rates in the wholesale markets are important for the traditional electric operating companies and Southern Power if they are to remain competitive in the wholesale markets in which they operate.
The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries cannot now be predicted.is uncertain. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs or otherwise negatively affect their results of operations.
The Southern Company system's costs of compliance with environmental laws are significant. The costs of compliance with current and future environmental laws including laws and regulations designed to address air quality, water, CCR, global climate change, and other matters and the incurrence of environmental liabilities could negatively impact the net income, cash flows, and financial condition of Southern Company, the traditional operating companies, and/or Southern Power.registrants.
The Southern Company system issystem's operations are subject to extensive federal,regulation by state and localfederal environmental requirements which, among other things, regulateagencies through a variety of laws and regulations governing air, emissions, water, usage and discharges,land, and the management and disposalprotection of waste in order to adequately protect the environment.other natural resources. Compliance with these existing environmental requirements requires the traditionalinvolves significant capital and operating companies and Southern Powercosts, a major portion of which is expected to commit significant expenditures for installation of pollution control equipment, environmental monitoring, emissions fees, and permits at substantiallybe recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all of their respective facilities. Southern Company, the traditional operating companies, and Southern Powersuch costs will be recovered. The registrants expect that these expenditures will continue to be significant in the future.
On October 23, 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. The proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stay will remain in effect through the resolution of the litigation, whether resolved in the D.C. Circuit or the Supreme Court.
Costs associated with these actions could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the final rules on the Southern Company system cannot be determined at this time
and will depend upon numerous factors, including the Southern Company system's ongoing review of the final rules; the outcome of legal challenges, including legal challenges filed by the traditional operating companies; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The EPA has adopted and is in the process of implementing regulations governing air and water quality, including the emission of nitrogen oxide, sulfur dioxide, fine particulate matter, ozone, mercury, and other air pollutants under the Clean Air Act. In addition, the EPA has finalizedAct and regulations governing cooling water intake structures and effluent guidelines for steam electric generating plants and amending the definition of Waters of the United States under the Clean Water Act. The EPA has also finalizedis reconsidering regulations governing the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at active power generation plants.
Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations affected by historical operations or subject to contractual obligations.
Existing environmental laws and regulations may be revised or new laws and regulations related to air, quality, water, CCR, global climate change, endangered species, orland, and the protection of other environmental and health concernsnatural resources may be adopted or become applicable to the traditional electric operating companies, Southern Power, and/or Southern Power.Company Gas.
The Southern Company system's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements
Table of new or revised environmental regulations; the time periods over which compliance with regulations is required; individual state implementation of regulations, as applicable; the outcome of any legal challengesContentsIndex to the environmental rules and any additional rulemaking activities in response to legal challenges and court decisions; the cost, availability, and existing inventory of emissions allowances; the impact of future changes in generation and emissions-related technology and costs; and the fuel mix of the electric utilities. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates or long-term wholesale agreements for the traditional operating companies or market-based rates for Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. Additionally, if Southern Company, any traditional operating company, or Southern Power fails to comply with environmental laws and regulations, even if caused by factors beyond its control, that failure may result in the assessment of civil or criminal penalties and fines and/or remediation costs.Financial Statements
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2and other emissions, CCR, releases of regulated substances, and alleged exposure to hazardous materials,regulated substances, and/or requests for injunctive relief in connection with such matters.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity or natural gas.
Compliance with any new or revised environmental laws or regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The ultimate impact will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may affect their demand for electricity and natural gas.
The Southern Company system may be exposed to regulatory and financial risks related to the impact of proposed and finalgreenhouse gas (GHG) legislation and regulation.
In 2015, the EPA published final rules limiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of the litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO2 emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing GHG emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.
Costs associated with these actions could be significant to the utility industry and the Southern Company system. However, the ultimate impact of these environmental laws and regulations will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future GHG constraints may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and litigation are likely tolow natural gas costs. Future GHG constraints focused on minimizing emissions from natural gas, albeit lower than other fossil fuels, could likewise result in significant additionalincreased costs to the Southern Company system and could result in additional operating restrictions.affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.
The net income of Southern Company, the traditional electric operating companies, and Southern Power could be negatively impacted by changes in regulations related to transmission planning processes and competition in the wholesale electric markets.
The traditional electric operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority of transmission revenues are collected through retail rates. FERC rules pertaining to regional transmission planning and cost allocation present challenges to transmission planning and the wholesale market structure in the Southeast. The key impacts of these rules include:
possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;
delays and additional processes for developing transmission plans; and
possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.
The FERC rules related to transmission are intended to spur the development of new transmission infrastructure to promote and encourage the integration of renewable sources of supply as well as facilitate competition in the wholesale market by providing more choices to wholesale power customers. In addition to the impacts on transactions contemplating physical delivery of energy, financial laws and regulations also impact power hedging and trading based on futures contracts and derivatives that are
traded on various commodities exchanges as well as over-the-counter. Finally, technologyTechnology changes in the power and fuel industries continue to create significant impacts to wholesale transaction cost structures. Southern Company, the traditional operating companies, and Southern Power cannot predict theThe impact of these and other such developments nor can they predictand the effect of changes in levels of wholesale supply and demand which are typically driven by factors beyond their control.uncertain. The financial condition, net income, and cash flows of Southern Company, the traditional electric operating companies, and Southern Power could be adversely affected by these and other changes.
The traditional electric operating companies and Southern Power could be subject to higher costs as a result of implementing and maintaining compliance with the North American Electric Reliability Corporation mandatory reliability standards along with possible associated penalties for non-compliance.
Owners and operators of bulk power systems, including the traditional electric operating companies, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation and enforced by the FERC. Compliance with or changes in the mandatory reliability standards may subject the traditional electric operating companies Southern Power, and Southern CompanyPower to higher operating costs and/or increased capital expenditures. If any traditional electric operating company or Southern Power is found to be in noncompliance with the mandatory reliabilitythese standards, such traditional electric operating company or Southern Power could be subject to sanctions, including substantial monetary penalties.
Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation, which has and could have a further material impact on the results of operations, financial condition, and cash flows of the registrants.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation significantly changes the U.S. Internal Revenue Code by, among other things, reducing the federal corporate income tax rate to 21% and repealing the corporate alternative minimum tax. As a result of the tax rate reduction, Southern Company recorded net, non-cash federal income tax benefits of $264 million in the fourth quarter 2017, comprised primarily of a $743 million tax benefit resulting from reductions in deferred tax liabilities at Southern Power, partially offset by tax expenses of $372 million and $93 million resulting from reductions in deferred tax assets at Mississippi Power and Southern Company Gas, respectively.
The tax rate reduction also resulted in a $6.9 billion increase in regulatory liabilities and a $0.4 billion decrease in regulatory assets across the traditional electric operating companies and the natural gas distribution utilities. The regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies.
For businesses other than regulated utility businesses, the Tax Reform Legislation allows 100% bonus depreciation of qualified property through 2022, which phases down through 2027, and limits interest expense deductions. Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. The Tax Reform Legislation retains normalization provisions for public utility property and existing renewable energy incentives. However, the tax rate reduction delays the utilization of renewable tax credit carryforwards as described in Note 5 to the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Power under "Federal Tax Reform Legislation" in Item 8 herein.
The Tax Reform Legislation also includes provisions that limit the utilization of future net operating losses and limit the deductibility of certain executive compensation and other expenses. Further, while it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as funds from operations to debt percentage, used by the credit rating agencies to assess the registrants, Southern Company Gas Capital, and Nicor Gas may be negatively impacted.
The Tax Reform Legislation is unclear in certain respects and will require interpretations, guidance, and implementing regulations by the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation and are assessing whether any potential actions are available to mitigate adverse impacts of the legislation. Southern Company and its subsidiaries may identify additional impacts as they further assess the Tax Reform Legislation and as the IRS issues interpretations and implements regulations. Southern Company will continue to monitor the actions of state legislatures and state taxing authorities to see how the states may adopt and implement the Tax Reform Legislation. While the ultimate impact of the Tax Reform Legislation, future interpretations and implementation of regulations by the IRS and state tax authorities, and any mitigating actions Southern Company and its subsidiaries may take cannot be determined at this time, the Tax Reform Legislation had and could have a further material impact on the results of operations, financial condition and cash flows of the registrants.
OPERATIONAL RISKS
The financial performance of Southern Company and its subsidiaries may be adversely affected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.
The financial performance of Southern Company and its subsidiaries depends on the successful operation of its subsidiaries'the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions. There are many risks that could affect these operations and performance of corporate functions, including:
operator error or failure of equipment or processes;
accidents or explosions;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
terrorist attacks (physical and/or cyber);
fuel or material supply interruptions;
transmission disruption or capacity constraints, including with respect to the Southern Company system’s transmission facilitiessystem's and third partyparties' transmission, storage, and transportation facilities;
compliance with mandatory reliability standards, including mandatory cyber security standards;
implementation of new technologies;
information technology system failure;
cyber intrusion;
an environmental event, such as a spill or release; and
catastrophic events such as fires, earthquakes, explosions, floods, droughts, hurricanes, tornadoes, and storms, pandemic health events such as influenzas, or other similar occurrences.
A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or natural gas distribution or storage facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional electric operating company, Southern Power, or Southern PowerCompany Gas and of Southern Company.
Operation of nuclear facilities involves inherent risks, including environmental, safety, health, regulatory, natural disasters, terrorism, and financial risks, that could result in fines or the closure of the nuclear units owned by Alabama Power or Georgia Power and which may present potential exposures in excess of insurance coverage.
Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represent approximately 3,680 MWs, or 8%, of the Southern Company system's electric generation capacity as of December 31, 2015.2017. In addition, these units generated approximately 23% and 25% of the total KWHs generated by each of Alabama Power and Georgia Power respectively, in the year ended December 31, 2015.2017. In addition, Southern Nuclear, on behalf of Georgia Power and the other co-owners,Vogtle Owners, is overseeingmanaging the construction of Plant Vogtle Units 3 and 4. Due solely to the increase in nuclear generating capacity, the below risks are expected to increase incrementally once Plant Vogtle Units 3 and 4 are operational. Nuclear
facilities are subject to environmental, safety, health, operational, and financial risks such as:
the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;
uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;
potential liabilities arising out of the operation of these facilities;
significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;
the threat of a possible terrorist attack, including a potential cyber security attack; and
the potential impact of an accident or natural disaster.
It is possible that damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, with NRC licensing and safety-related requirements, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a serious nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units or require additional safety measures at new and existing units. Moreover, a major incident at any nuclear facility in the U.S., including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.
In addition, potential terrorist threats and increased public scrutiny of utilities could result in increased nuclear licensing or compliance costs that are difficult to predict.
PhysicalTransporting and storing natural gas involves risks that may result in accidents and other operating risks and costs.
Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these regulatory requirements could result in substantial monetary penalties or cyberpotential early retirement of storage facilities, which could trigger an associated impairment. The occurrence of any of these events not fully covered by insurance or otherwise could adversely affect Southern Company Gas' and Southern Company's financial condition and results of operations.
Physical attacks, both threatened and actual, could impact the ability of the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas to operate and could adversely affect financial results and liquidity.
The traditional electric operating companies, Southern Power, and Southern PowerCompany Gas face the risk of physical and cyber attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport power, and their information technology systems and network infrastructure,energy, which could negatively impact thetheir ability of the traditional operating companies or Southern Power to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on Southern Company and its subsidiaries.
The traditional operating companies and Southern Power operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure, which are part of an interconnected regional grid. In addition, in the ordinary course of business, the traditional operating companies and Southern Power collect and retain sensitive information including personal identification information about customers and employees and other confidential information. The traditional operating companies and Southern Power face on-going threats to their assets. Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical or cyber attacks. If the traditional operating companies' or Southern Power's assets were to fail, be physically damaged, or be breached and were not recovered in a timely way, the traditional electric operating companies, Southern Power, or Southern Company Gas, as applicable, may be unable to fulfill critical business functions. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or physical security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
These events could harm the reputation of and negatively affect the financial results of the registrants through lost revenues and costs to repair damage, if such costs cannot be recovered.
An information security incident, including a cybersecurity breach, or the failure of one or more key information technology systems, networks, or processes could impact the ability of the registrants to operate and could adversely affect financial results and liquidity.
Information security risks have generally increased in recent years as a result of the proliferation of new technology and increased sophistication and frequency of cyber attacks and data security breaches. The traditional electric operating
companies, Southern Power, and Southern Company Gas operate in highly regulated industries that require the continued operation of sophisticated information technology systems and network infrastructure, which are part of interconnected distribution systems. Because of the critical nature of the infrastructure, increased connectivity to the internet, and technology systems' inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, or other types of data security breaches, Southern Company and its subsidiaries face a heightened risk of cyberattack. Parties that wish to disrupt the U.S. bulk power system or Southern Company system operations could view these computer systems, software, or networks as targets. The registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their information technology systems and confidential data or to attempts to disrupt utility operations. As a result, Southern Company and its subsidiaries face on-going threats to their assets, including assets deemed critical infrastructure, where databases and systems have been, and will likely continue to be, subject to advanced computer viruses or other malicious codes, unauthorized access attempts, phishing, and other cyber attacks. While there has been no material impact on business or operations from these attacks, the registrants cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure.
In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third party service providers that could also be targets of cyber attacks. Generally, Southern Company and its subsidiaries enter certain contractual security guarantees and assurances with these third parties to help ensure the security and safety of this information.
Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external cyber attacks. If assets were to fail or be breached and were not recovered in a timely way, the affected registrant may be unable to fulfill critical business functions, and sensitive and other data could be compromised. Any physical security breach, cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the applicable traditional operating company or Southern Poweraffected registrant to penalties and claims from regulators or other third parties.
These events could harm the reputation of and negatively affect the financial results of Southern Company, the traditional operating companies, or Southern Powerregistrants through lost revenues, costs to recover and repair damage, and costs associated with governmental actions in response to such attacks.attacks, litigation, and reputational damage if such costs cannot be recovered through insurance or otherwise.
The traditional operating companies and Southern PowerCompany system may not be able to obtain adequate natural gas and other fuel supplies which could limit their abilityrequired to operate theirfacilities.the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.
The traditional electric operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, as applicable, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs and potentially reduce the net income of the affected traditional electric operating company or Southern Power and Southern Company.
Southern Company Gas' primary business is the distribution and sale of natural gas through its regulated and unregulated subsidiaries. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane or a pipeline failure. Southern Company Gas also relies on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to Southern Company Gas' distribution systems. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Disruption in natural gas supplies could limit the ability to fulfill these contractual obligations.
The traditional electric operating companies and Southern Power have become more dependent on natural gas for a portion of their electric generating capacity. In many instances, the cost of purchased power for the traditional electric operating companies and Southern Power is influenced by natural gas prices. Historically, natural gas prices have been more volatile than prices of other fuels. In recent years, domestic natural gas prices have been depressed by robust supplies, including production from shale gas. These market conditions, together with additional regulation of coal-fired generating units, have increased the traditional electric operating companies' reliance on natural gas-fired generating units.
Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane, freezing wells, or a pipeline failure. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas.
The traditional electric operating companies are also dependent on coal for a portion of their electric generating capacity. The traditional electric operating companies depend on coal supply contracts, and there can be no assurance that the counterparties to these agreements willmay not fulfill their obligations to supply coal to the traditional electric operating companies. The suppliers under these agreements may experience financial or
technical problems that inhibit their ability to fulfill their obligations to the traditional operating companies.obligations. In addition, the suppliers under these agreements may not be required to supply coal to the traditional operating companies under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their coal requirements under these contracts, the traditional operating companiesthey may be required to purchase their coal requirements at higher prices, which may not be recoverable through rates.
The revenues of Southern Company, the traditional electric operating companies, and Southern Power depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, the failure of the traditional electric operating companies or Southern Power to satisfy minimum requirements under the PPAs, or the failure to renew the PPAs or successfully remarket the related generating capacity could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company.
Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power’sPower's top three customers, Georgia Power, Florida Power & Light Company, and Duke Energy Corporation, and Morgan Stanley Capital Group accounted for 15.8%11.3%, 10.7%6.7%, and 8.2%4.5%, respectively, of Southern Power’sPower's total revenues for the year ended December 31, 2015.2017. In addition, the traditional electric operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. The failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.
Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. As an example, Gulf Power had long-term sales contracts to cover 100% of its ownership share of Plant Scherer Unit 3 (205 MWs) and these capacity revenues represented 82% of Gulf Power's total wholesale capacity revenues for 2015. Due to the expiration of a wholesale contract at the end of 2015 and future expiration dates of the remaining wholesale contracts for the unit, Gulf Power currently has contracts to cover 34% of the unit for 2016 and 27% of the unit through 2019. Although Gulf Power is actively evaluating alternatives relating to this asset, including replacement wholesale contracts, the expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years. In addition, theThe failure of the traditional electric operating companies or Southern Power to satisfy minimum operational or availability requirements under these PPAs could result in payment of damages or termination of the PPAs.
The asset management arrangements between Southern Company Gas' wholesale gas services and its customers, including the natural gas distribution utilities, may not be renewed or may be renewed at lower levels, which could have a significant impact on Southern Company Gas' financial results.
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Southern Company Gas' wholesale gas services also has asset management agreements with certain non-affiliated customers and its financial results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.
Increased competition could negatively impact Southern Company's and its subsidiaries' revenues, results of operations, and financial condition.
The Southern Company system faces increasing competition from other companies that supply energy or generation and storage technologies. Changes in technology may make the Southern Company'sCompany system's electric generating facilitiesowned by the traditional electric operating companies and Southern Power less competitive. Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas also faces competition in its unregulated markets.
A key element of the business models of Southern Company, the traditional electric operating companies and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation and storage technologies that produce and store power, including fuel cells, microturbines, wind turbines, solar cells, and batteries. Advances in technology or changes in laws or regulations could reduce the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation.generation that allows for increased self-generation by customers. Broader use of distributed generation by retail electricenergy customers may also result from customers’customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, there can be no assurance that a state PSC or legislature will not attempt tomay modify certain aspects of the traditional electric operating companies’companies' business as a result of these advances in technology. If these technologies became cost competitive and achieve sufficient scale, the market share
It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional electric operating companies, or Southern Power.
Southern Company Gas' gas marketing services is affected by competition from other energy marketers providing similar services in Southern Company Gas' service territories, most notably in Illinois and Georgia. Southern Company Gas' wholesale gas services competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines based on the ability to aggregate competitively-priced commodities with transportation and storage capacity. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region.
If new technologies become cost competitive and achieve sufficient scale, the market share of the traditional electric operating companies, Southern Power, and Southern Company Gas could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets. If state PSCs or other applicable state regulatory agencies fail to adjust rates to reflect the impact of any changes in loads, increasing self-generation, and the growth of distributed generation, the financial condition, results of operations, and cash flows of Southern Company and the affected traditional electric operating companiescompany or Southern Company Gas could be materially adversely affected.
Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company's and its subsidiaries' results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with major construction projects and ongoing operations. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses. If Southern Company and its subsidiaries including the traditional operating companies, are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
CONSTRUCTION RISKS
Southern Company, the traditional operating companies, and/or Southern PowerThe registrants may incur additional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities of the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas require ongoing capital expenditures, including those to meet environmental standards.
General
The businesses of the registrants require substantial capital expenditures for investments in new facilities and, for the traditional electric operating companies, capital improvements to transmission, distribution, and generation facilities, and, for Southern Company Gas, capital improvements to natural gas distribution and storage facilities, including those to meet environmental standards. Certain of the traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company Gas is replacing certain pipelines in its natural gas distribution system and is involved in two new gas pipeline construction projects. The Southern Company system intends to continue its strategy of developing and constructing other new facilities, expanding or updating existing facilities, and adding environmental control equipment. These types of projects are long-termlong term in nature and in some cases include the development and construction of facilities with designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:
shortages and inconsistent quality of equipment, materials, and labor;
changes in labor costs and productivity;
work stoppages;
contractor or supplier delay or non-performance under construction, operating, or other agreements or non-performance by other major participants in construction projects;
delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;
delays associated with start-up activities, including major equipment failure and system integration, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC)PSC or other applicable state regulatory agency);
operational readiness, including specialized operator training and required site safety programs;
impacts of new and existing laws and regulations, including environmental laws and regulations;
the outcome of legal challenges to projects, including legal challenges to regulatory approvals;
failure to construct in accordance with permitting and licensing requirements;
failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;
continued public and policymaker support for such projects;
adverse weather conditions or natural disasters;
other unforeseen engineering or design problems;
changes in project design or scope;
environmental and geological conditions;
delays or increased costs to interconnect facilities to transmission grids; and
unanticipated cost increases, including materials and labor, and increased financing costs as a result of changes in market interest rates or as a result of construction schedule delays.
If a traditional electric operating company, Southern Power, or Southern PowerCompany Gas is unable to complete the development or construction of a facilityproject or decides to delay or cancel construction of a facility,project, it may not be able to recover its investment in that facilityproject and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Additionally, each Southern Company Gas pipeline construction project involves separate joint venture participants, Southern Power participates in partnership agreements with respect to renewable energy projects, and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction.
Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and there is no assurance that the traditional operating company willmay not be able to recover such expendituresrecoverable through regulated rates.rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of a traditional operating company or Southern Power and of Southern Company.the affected registrant.
Construction delays could result in the loss of otherwise available investment tax credits, production tax credits,PTCs, and other tax incentives. Furthermore, if construction projects are not completed according to specification, a traditional electric operating company, Southern Power, or Southern PowerCompany Gas and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities come into commercial operation,become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide safe and reliable operations.
The two largest construction projectsproject currently underway in the Southern Company system areis Plant Vogtle Units 3 and 4.
Plant Vogtle Units 3 and 4 construction and rate recovery
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under a substantially fixed price engineering, procurement, and construction agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the EPC Contractor to allow construction to continue (Interim Assessment Agreement). The Interim Assessment Agreement expired on July 27, 2017 upon the effectiveness of a services agreement between the Vogtle Owners and the EPC Contractor for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear (Vogtle Services Agreement). In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth Vogtle Construction Monitoring (VCM) report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel Power Corporation (Bechtel) serving as the primary construction contractor. Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The construction completion agreement between Georgia Power, for itself and as agent for the other Vogtle Owners, and Bechtel (Bechtel Agreement) is a cost reimbursable plus
fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 andwill not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the Kemper IGCC.construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, Southern Power has 691 MWs (based on its equity ownership)pursuant to the Vogtle Joint Ownership Agreements, the required approval of renewable generation under construction at eight project sites.
holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction
contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on behalfJanuary 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of Georgia Powerthe $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the December 31, 2015 agreement between Westinghouse and the other co-owners, is overseeingVogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the original engineering, procurement, and construction of and will operateagreement for Plant Vogtle Units 3 and 4 (each,(Contractor Settlement Agreement) was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined below) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the return on equity (ROE) used to calculate the Nuclear Construction Cost Recovery (NCCR) tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 Alternative Rate Plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for allowance for funds used during construction equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the settlement agreement approved by the Georgia PSC on December 20, 2016. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an approximately 1,100 MW AP1000 nuclear generating unit)adverse outcome in this appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding Toshiba's guarantee of certain obligations of the EPC Contractor (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power owns 45.7%Power's construction work in progress balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new units. The NRC certifiedtechnology and have not yet operated in the Westinghouse Design Control Document, as amended (DCD)global nuclear industry at this scale), foror other issues could arise and change the AP1000 nuclear reactor design, in late 2011,projected schedule and issued combined COLs in early 2012. Receipt of the COLs allowed full construction to begin. estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise as construction proceeds.
Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC’s procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap.
In 2012, the Vogtle Owners and the Contractor commenced litigation (Vogtle Construction Litigation) regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the engineering, procurement, and construction contract between the Vogtle Owners and the Contractor (Vogtle 3 and 4 Agreement).
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor’s ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security,for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, Chicago Bridge & Iron Company N.V., and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and Georgia Power’s position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following Georgia Power’s filing under the order, the Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in
service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6 billion as of December 31, 2015.
arise. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issuesmatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.costs.
As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the Internal Revenue Service allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.
Kemper IGCC construction
In 2012, the Mississippi PSC issued a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC (2012 MPSC CPCN Order). The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.
Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). Southern Company and Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $365 million ($226 million after tax), $868 million ($536 million after tax), and $1.1 billion ($681 million after tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC’s projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels.
Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month.
Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or
supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company’s and Mississippi Power's statements of operations and these changes could be material.
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.
On February 12, 2015, the Mississippi Supreme Court (Court) issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the rates be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million.
As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power filed a request for interim rates with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between Mississippi Power and the Mississippi Public Utilities Staff regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, the In-Service Asset Rate Order provides for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power’s actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period. The In-Service Asset Rate Order also includes a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.
With implementation of the new rate on December 17, 2015, the interim rates were terminated and Mississippi Power recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. Mississippi Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations. The ultimate outcome of this matterthese matters cannot be determined at this time.
LegislationSee Note 3 to authorize a multi-year rate planthe financial statements of Southern Company under "Nuclear Construction" and legislation to provideof Georgia Power under "Retail Regulatory Matters - Nuclear Construction" for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into lawadditional information regarding Plant Vogtle Units 3 and 4.
Southern Company Gas' significant investments in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costspipelines and pipeline development projects involve financial and execution risks.
Southern Company Gas has made significant investments in excessexisting pipelines and pipeline development projects. Many of the certificated cost estimateexisting pipelines are, and when completed many of $2.4 billion. Qualifying facility costs include, but are not limitedthe pipeline development projects will be, operated by third parties. If one of these agents fails to pre-construction costs, construction costs, regulatory costs,perform in a proper manner, the value of the investment could decline and accrued AFUDC.
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power that it was terminating the agreement. Mississippi Power had previously received a total of $275 million of deposits from SMEPA that were returned by Southern Company to SMEPA, with interest of approximately $26 million, on June 3, 2015, as a resultGas could lose part or all of the
termination, pursuant to its guarantee obligation. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million totime, Southern Company which matures December 1, 2017. The In-Service Asset Proposal andGas may be required to contribute additional capital to a pipeline joint venture or guarantee the related rates approved by the Mississippi PSC excluded any costs associated with the 15% undivided interest. Mississippi Power continues to evaluate its alternatives withobligations of such joint venture.
With respect to certain pipeline development projects, Southern Company Gas will rely on its investmentjoint venture partners for construction management and will not exercise direct control over the related costs associated with the 15% undivided interest.
Mississippi Power expects to seek additional rate relief to address recoveryprocess. All of the remaining Kemper IGCC assets. In additionpipeline development projects are dependent on contractors for the successful and timely completion of the projects. Further, the development of pipeline projects involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require the expenditure of significant amounts of capital. These projects may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' capital expenditures to current estimated costs at December 31, 2015exceed its initial expectations. Moreover, Southern Company Gas' revenues will not increase immediately upon the expenditure of $6.63 billion, Mississippi Power anticipates that itfunds on a pipeline project. Pipeline construction occurs over an extended period of time and Southern Company Gas will incur additional costs after the Kemper IGCC in-service datenot receive material increases in revenues until the Kemper IGCC cost recovery approachproject is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recoveryplaced in service.
The occurrence of these costs would be subject to approval by the Mississippi PSC.
Mississippi Power also expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operationany of the Kemper IGCC. Toforegoing events could adversely affect the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power'sresults of operations, cash flows, and financial statements.
Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiarycondition of Denbury Resources Inc.,Southern Company Gas and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the CO2 agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in Mississippi Power’s revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.
The ultimate outcome of these matters, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, is subject to further regulatory actions and cannot be determined at this time.Southern Company.
FINANCIAL, ECONOMIC, AND MARKET RISKS
The electric generation operations and energy marketing operations of Southern Company, the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to risks, many of which are beyond their control, including changes in powerenergy prices and fuel costs, which may reduceSouthern Company's, the traditional operating companies', and/or Southern Power'srevenues and increase costs.
The generation, operationsenergy marketing, and energy marketingnatural gas operations of the Southern Company system are subject to changes in powerenergy prices and fuel costs, which could increase the cost of producing power, or decrease the amount received from the sale of power.energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Among the factors that could influence powerenergy prices and fuel costs are:
prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;
demand for energy and the extent of additional supplies of energy available from current or new competitors;
liquidity in the general wholesale electricity market;and natural gas markets;
weather conditions impacting demand for electricity;electricity and natural gas;
seasonality;
transmission or transportation constraints, disruptions, or inefficiencies;
availability of competitively priced alternative energy sources;
forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;
the financial condition of market participants;
the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels;fuels, including natural gas;
natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and
federal, state, and foreign energy and environmental regulation and legislation.
Certain of these factors could increase the expenses of the traditional electric operating companies, Southern Power, or Southern PowerCompany Gas and Southern Company. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional electric operating companies, Southern Power, or Southern PowerCompany Gas and Southern Company.
Historically, the traditional electric operating companies and Southern Company Gas from time to time have experienced underrecovered fuel and/or purchased gas cost balances and may experience such balances in the future. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through fuel cost recovery clauses, recovery may be denied if costs are deemed to be imprudently incurred, and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional electric operating company or Southern Company Gas and Southern Company.
Southern Company, the traditional operating companies, and Southern PowerThe registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the traditional electric operating companies, Southern Power, and Southern Power.Company Gas.
The consumption and use of energy are fundamentally linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. Any economic downturn could negatively impact customer growth and usage per customer, thus reducing the sales of electricityenergy and revenues. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the traditional electric operating companies, Southern Power, and Southern Power.Company Gas.
Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of electricity.energy.
Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and Southern Company Gas have PSC or other applicable state regulatory agency mandates to promote energy efficiency. Conservation programs could impact the financial results of Southern Company, the traditional operating companies, and Southern Powerregistrants in different ways. For example, if any traditional electric operating company or Southern Company Gas is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional electric operating company or Southern Company Gas and Southern Company. Customers could also voluntarily reduce their consumption of electricityenergy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.
In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, new electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. There can be no assurance that theThe Southern Company system's planning processes will appropriately estimatesystem uses best available methods and experience to incorporate the impactseffects of changes in customer behavior, state and federal programs, PSC or other applicable state regulatory agency mandates, and technology.technology, but the Southern Company system's planning processes may not appropriately estimate and incorporate these effects.
All of the factors discussed above could adversely affect Southern Company's, the traditional electric operating companies', Southern Power's, and/or Southern Power'sCompany Gas' results of operations, financial condition, and liquidity.
The operating results of Southern Company, the traditional operating companies, andSouthern Powerregistrants are affected by weather conditions and may fluctuate on a seasonal and quarterly basis. In addition, significant weathercatastrophic events, such as fires, earthquakes, hurricanes, tornadoes, floods, droughts, and winter storms, could result in substantial damage to or limit the operation of the properties of the traditional electric operating companies, Southern Power, and/or Southern PowerCompany Gas and could negatively impact results of operation, financial condition, and liquidity.
Electric power and natural gas supply isare generally a seasonal business.businesses. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional operating companies, and Southern Powerregistrants may fluctuate substantially on a seasonal basis. In addition, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas have historically sold less
power and natural gas when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, and available cash of Southern Company, the traditional operating companies, and/or Southern Power.affected registrant.
In addition,Further, volatile or significant weather events could result in substantial damage to the transmission and distribution lines of
the traditional electric operating companies, and the generating facilities of the traditional operating companies and Southern Power. The traditionalelectric operating companies and Southern Power, and the natural gas distribution and storage facilities of Southern Company Gas. The traditional electric operating companies, Southern Power, and Southern Company Gas have significant investments in the Atlantic and Gulf Coast regions and Southern Power has wind and natural gas investments in Oklahomavarious states which could be subject to major storm activity.severe weather, as well as solar investments in various states which could be subject to natural disasters. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.
In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC.PSC or other applicable state regulatory agency. Historically, the traditional electric operating companies from time to time have experienced deficits in their storm cost recovery reserve balances and may experience such deficits in the future. Any denial by the applicable state PSC or other applicable state regulatory agency or delay in recovery of any portion of such costs could have a material negative impact on a traditional electric operating company's or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.
In addition, damages resulting from significant weather events within the service territory of any traditional electric operating company or Southern Company Gas or affecting Southern Power's customers may result in the loss of customers and reduced demand for electricityenergy for extended periods. Any significant loss of customers or reduction in demand for electricityenergy could have a material negative impact on a traditional electric operating company's, Southern Power's, or Southern Power'sCompany Gas' and Southern Company's results of operations, financial condition, and liquidity.
Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
Southern Company and its subsidiaries have made significant acquisitions and investments in the past and may in the future make additional acquisitions, dispositions, or other strategic ventures or investments, including the proposed sale by Pivotal Utility Holdings, a wholly-owned subsidiary of Southern Company Gas, of the assets of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, and the potential sale by Southern Power of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers.
Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk. These transactions may also affect the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
These transactions also involve risks, including:
they may not result in an increase in income or provide an adequate return on capital or other anticipated benefits;
they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;
they may not be successfully integrated into the acquiring company's operations and/or internal control processes;
the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;
they may result in decreased earnings, revenues, or cash flow;
expected benefits of a transaction may be unabledependent on the cooperation or performance of a counterparty; or
for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through rates may not be recoverable.
Southern Company and Southern Company Gas are holding companies and are dependent on cash flows from their respective subsidiaries to meet itstheir ongoing and future financial obligations, including making interest and principal payments on outstanding indebtedness and, for Southern Company, to pay dividends on its common stock if its subsidiaries are unable to payupstream dividends or repay funds to Southern Company.stock.
Southern Company is aand Southern Company Gas are holding companycompanies and, as such, Southern Company hasthey have no operations of itstheir own. Substantially all of Southern Company's and Southern Company Gas' respective consolidated assets are held by subsidiaries. A significant portion of Southern Company Gas' debt is issued by its 100%-owned subsidiary, Southern Company Gas Capital, and is fully and unconditionally guaranteed by Southern Company Gas. Southern Company's and Southern Company Gas' ability to meet itstheir respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is primarily dependent on the net income and cash flows of itstheir respective subsidiaries and theirthe ability of those subsidiaries to pay upstream dividends or to repay funds to Southern Company.borrowed funds. Prior to funding Southern Company or Southern Company'sCompany Gas, the respective subsidiaries have regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred and preference stock dividends. Southern Company'sThese subsidiaries are separate legal entities and have no obligation to provide Southern Company or Southern Company Gas with funds. In addition, Southern Company and Southern Company Gas may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce Southern Company’sthe funds available to meet itstheir respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on itsSouthern Company's common stock.
A downgrade in the credit ratings of Southern Company, any of the traditional operating companies,registrants, Southern Company Gas Capital, or Southern PowerNicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require Southern Company, the traditional operating companies, or Southern Power to postposting of collateral or replacereplacing certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for the registrants, Southern Company the traditional operating companies,Gas Capital, and Southern Power,Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. The registrants, Southern Company the traditional operating companies,Gas Capital, and Southern PowerNicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or Southern Company, the traditional operating companies, or Southern Powerapplicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any registrant, Southern Company the traditional operating companies,Gas Capital, or Southern Power,Nicor Gas, borrowing costs likely would increase, including automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require a traditional operating company or Southern Power to alteraltering the mix of debt financing currently used, and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants.covenants binding the applicable company.
Uncertainty in demand for powerenergy can result in lower earnings or higher costs. If demand for powerenergy falls short of expectations, it could result in potentially stranded assets. If demand for powerenergy exceeds expectations, it could result in increased costs for purchasing capacity in the open market or building additional electric generation and transmission facilities or natural gas distribution and storage facilities.
Southern Company, the traditional electric operating companies, and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. ThisSouthern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines and storage facilities, replacing existing pipelines, rewatering storage facilities, and entering new markets and/or expanding in existing markets. These planning processes must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution and storage facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including regional economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional electric operating companies or Southern Company Gas' regulated operating companies to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, the traditional operating companiesSouthern Company and its subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of additional capacity and the traditional operating companies' recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-
basedmarket-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend existing PPAs or to find new buyers for existing generation assets as existing PPAs expire, or they may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and for Southern Company.registrant.
The traditional electric operating companies and Southern Power are currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-
term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies or Southern Power purchase capacity on the open market or build additional generation and transmission facilities.facilities, and for Southern Power to purchase energy or capacity on the open market. Because regulators may not permit the traditional electric operating companies to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power wouldmay not have the abilitybe able to recover anyall of these costs. These situations could have negative impacts on net income and cash flows for the affected traditional operating company or Southern Power and for Southern Company.registrant.
The businesses of Southern Company, the traditional operating companies,registrants and SouthernPowerNicor Gas are dependent on their ability to successfully access funds through capital markets and financial institutions. The inability of Southern Company, any traditional operating company,of the registrants or Southern PowerNicor Gas toaccess funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operatingcompanies, or Southern Powerit may otherwise rely on to achieve future earnings and cash flows.
Southern Company, the traditional operating companies,The registrants and Southern PowerNicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If Southern Company, any traditional operating company,of the registrants or Southern PowerNicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that Southern Company, the traditional operating companies, or Southern Powerit may otherwise rely on to achieve future earnings and cash flows. In addition, Southern Company, the traditional operating companies,registrants and Southern PowerNicor Gas rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of Southern Company, the traditional operating companies,registrants and Southern PowerNicor Gas believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain events or market disruptions may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:
an economic downturn or uncertainty;
bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;
capital markets volatility and disruption, either nationally or internationally;
changes in tax policy such as dividend tax rates;policy;
volatility in market prices for electricity and natural gas;
terrorist attacks or threatened attacks on the Southern Company'sCompany system's facilities or unrelated energy companies' facilities;
war or threat of war; or
the overall health of the utility and financial institution industries.
As of December 31, 2017, Mississippi Power’s financial condition and its abilityPower's current liabilities exceeded current assets by approximately $911 million primarily due to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were adversely affected by (i) the return of approximately $301a $900 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA; (ii) the required refund of approximately $371 million of rate collections, including associated carrying costs, and the termination of those rates; and (iii) the required recapture of Phase II tax credits.unsecured term loan that matures on March 31, 2018. Mississippi Power expects to refinance its 2016 debt maturitiesthe unsecured term loan with bank term loans.external security issuances and/or borrowings from financial institutions or Southern Company. Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to utilize operating cash flows and lines of credit (to the extent available) as well asprovide Mississippi Power with loans and, under certain circumstances,and/or equity contributions from Southern Company to fund the remainder of Mississippi Power’s capital needs.remaining indebtedness to mature and other cash needs over the next 12 months.
In addition, Georgia Power’sPower's ability to make future borrowings through its term loan credit facility with the Federal Financing Bank is subject to the satisfaction of customary conditions, as well as certification of compliance with the requirements of the loan guarantee program under Title XVII of the Energy Policy Act of 2005, including accuracy of project-related representations and warranties, delivery of updated project-related information and evidence of compliance with the prevailing
wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE’sDOE's consulting engineer that proceeds of the advances are used to reimburse certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Prior to obtaining any further advances under Georgia Power's loan guarantee agreement with the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement.
Failure to comply with debt covenants or conditions could adversely affect the ability of the registrants, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.
The debt and credit agreements of the registrants, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements, which would negatively affect the applicable company's financial condition and liquidity.
Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning.
The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of the Southern Company system’ssystem's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension planplans with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission Alabama Power’sPower's and Georgia Power’sPower's nuclear plants. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.
Southern Company, the traditional operating companies, and Southern PowerThe registrants are subjectto risks associated with their ability toobtain adequate insurance at acceptable costs.
The financial condition of some insurance companies, the threat of terrorism, and natural disasters, among other things, could have disruptive effects on insurance markets. The availability of insurance covering risks that Southern Company, the traditional operating companies, Southern Power,registrants and their respective competitors typically insure against may decrease, and the insurance that Southern Company, the traditional operating companies, and Southern Powerregistrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, there is no guarantee that the insurance policies maintained by the Southern Company, the traditional operating companies, and Southern Power willmay not cover all of the potential exposures or the actual amount of loss incurred.
Any losses not covered by insurance, or any increases in the cost of applicable insurance, could adversely affect the results of operations, cash flows, or financial condition of Southern Company, the traditional operating companies, or Southern Power.affected registrant.
The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the net income of Southern Company and its subsidiaries.the registrants or in reported net income volatility.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Power,Company Gas, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage foreign currency exchange rate exposure and engage in limited trading activities. Southern Company and its subsidiariesThe registrants could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures. These risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not off-setoffset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts.
ACQUISITION RISKS
Acquisitions and dispositionsIn addition, Southern Company Gas utilizes derivative instruments to lock in economic value in wholesale gas services, which may not resultqualify or are not designated as hedges for accounting purposes. The difference in anticipated benefitsaccounting treatment for the underlying position and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, resultsfinancial instrument used to hedge the value of operations, and financial conditionthe contract can cause volatility in reported net income of Southern Company and its subsidiaries.
Southern Company and its subsidiaries have made significant acquisitions and dispositions inGas while the past and may in the future make additional acquisitions and dispositions. Southern Power, in particular, continually seeks opportunitiespositions are open due to create value through various transactions, including acquisitionsmark-to-market accounting.
Future impairments of goodwill or sales of assets.
Southern Company and its subsidiaries may face significant competition for acquisition opportunities and there can be no assurance that anticipated acquisitions will be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or
the reduction of risk. These transactions may also affect the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
These transactions also involve risks, including:
any acquisitions may not result in an increase in income or provide an adequate return on capital or other anticipated benefits;
any acquisitions may not be successfully integrated into the acquiring company’s operations and internal controls processes;
the due diligence conducted prior to an acquisition may not uncover situations that could result in financial or legal exposure or the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;
any disposition may result in decreased earnings, revenue, or cash flow;
use of cash for acquisitions may adversely affect cash available for capital expenditures and other uses; or
any dispositions, investments, or acquisitionslong-lived assets could have a material adverse effect on the liquidity,registrants' results of operations,operations.
Goodwill is assessed for impairment at least annually and more frequently if events or financial conditioncircumstances occur that would more likely than not reduce the fair value of Southern Companya reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or its subsidiaries.
Southern Company and AGL Resourcescircumstances indicate that an asset's carrying amount may encounter difficulties in satisfying the conditions fornot be recoverable. In connection with the completion of the Merger, including receiptthe application of all required regulatory approvals, which could delay the completion of the Merger or impose conditions that could have a material adverse effect on the combined company or that could cause either party to abandon the Merger.
Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, and Maryland PSC, New Jersey Board of Public Utilities, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.
Southern Company completed the required state regulatory filings in the fourth quarter 2015 and the required FCC filings in February 2016. On February 24, 2016, a stipulation and settlement agreement between Southern Company, AGL Resources, the Maryland PSC Staff, and the Maryland Office of People's Counsel was filed with the Maryland PSC. The proposed settlement remains subject to the approval of the Maryland PSC. Additionally, Southern Company received the approval of the Virginia State Corporation Commission in February 2016.
These governmental entities may decline to approve the Merger or may impose conditions on the completion, or require changes to the terms, of the Merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following the Merger.
Satisfying the conditions to completion of the Merger may take longer, and could cost more, than Southern Company expects. Any delay in completing the Merger or any additional conditions imposed in order to complete the Merger may materially adversely affect the benefits that Southern Company expects to achieve from the Merger and the integration of the companies' respective businesses.
In addition, conditions to the completion of the Merger may fail to be satisfied. Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied.
Any delay in completing the Merger, conditions imposed by governmental entities, or failure to complete the Merger could have a material adverse effect on the financial condition, net income, and cash flows of Southern Company.
Failure to complete the Merger could negatively impact Southern Company's stock price and Southern Company's future business and financial results.
Completion of the Merger is not assured and is subject to risks, including the risks that approval of the transaction by governmental entities will not be obtained or that certain other closing conditions will not be satisfied. If the Merger is not
completed, Southern Company's ongoing businesses and financial results may be adversely affected and Southern Company will be subject to a number of risks, including the following:
Southern Company will be required to pay significant costs relating to the Merger, including legal, accounting, and financial advisory costs, whether or not the Merger is completed;
matters relating to the Merger (including integration planning) may require substantial commitments of time and resources by Southern Company management, which could otherwise have been devoted to other opportunities that may have been beneficial to Southern Company; and
negative publicity and a negative impression of Southern Company in the investment community.
The occurrence of any of these events, individually or in combination, could cause the share price of Southern Company to decline if and to the extent that the current market prices reflect an assumption by the market that the Merger will be completed.
If completed, the Merger may not achieve its intended results.
Southern Company entered into the Merger Agreement with the expectation that the Merger would result in various benefits. Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including whether the business of AGL Resources is integrated in an efficient and effective manner, conditions imposed on the Merger by federal and state public utility, antitrust, and other regulatory authorities prior to approval, general market and economic conditions, and general competitive factors in the marketplace. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company, and diversion of management's time and energy and could have an adverse effect on the combined company's financial condition, net income, and cash flows.
The Southern Company system will be subject to business uncertainties while the Merger is pending that could adversely affect Southern Company's financial results.
Uncertainty about the effect of the Merger on employees, suppliers, and customers of the Southern Company system may have an adverse effect on Southern Company. These uncertainties may impair the Southern Company system's ability to attract, retain, and motivate key personnel until the Merger is completed and for a period of time thereafter and could cause customers, suppliers, and others that deal with the Southern Company system to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If key employees depart or fail to accept employment with the Southern Company system because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, Southern Company's financial results could be adversely affected.
The pursuit of the Merger and the preparation for the integration of AGL Resources into the Southern Company system may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could adversely affect Southern Company's financial condition, net income, and cash flows.
Southern Company is obligated to complete the Merger whether or not it has obtained the required financing.
Southern Company intends to initially fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue approximately $8.0 billion in debt prior to closing the Merger and approximately $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, Southern Power growth opportunities, and other Southern Company system capital projects. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. The Bridge Agreement is subject to various conditions contained in the Bridge Agreement and the issuance of long-term debt and equity sales to finance the Merger will be subject to future market conditions.
Following the Merger, stockholders of Southern Company will own equity interests in a company whose subsidiary owns and operates a natural gas business.
AGL Resources is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. AGL Resources is involved in several other businesses that are mainly related and complementary to its primary business including: retail operations including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, the combined company will be subject to various risks to which Southern Company is not currently subject, including risks related to transporting and storing natural gas. As stockholders of the combined company following the Merger, Southern Company stockholders may be adversely affected by these risks.
Southern Company expects to record goodwill that could become impaired and adversely affect its operating results.
In accordance with GAAP, the Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date.was pushed down to Southern Company Gas. The excess of the purchase price over the fair values of AGL Resources'Southern Company Gas' assets and liabilities will bewas recorded as goodwill.
The amount of This resulted in a significant increase in the goodwill which is expected to be material, will be allocated to the appropriate reporting units of the combined company.recorded on Southern Company's and Southern Company is required to assessGas' consolidated balance sheets. At December 31, 2017, goodwill was $6.3 billion and $6.0 billion for impairment at least annually by comparing the fair value of reporting units to the carrying value of those reporting units.Southern Company and Southern Company Gas, respectively.
In addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the carrying value of any of those reporting units is greater than the fair value, a second step comparing the implied fair value of goodwill toor long-lived assets become impaired, the carrying amount wouldaffected registrant may be required to determine if the goodwill is impaired. Such a potentialincur impairment could result in a material chargecharges that wouldcould have a material impact on their results of operations. For example, a wholly-owned subsidiary of Southern Company
Gas owns and operates a natural gas storage facility consisting of two salt dome caverns where recent seismic mapping indicates that proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. In addition, a subsidiary of Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. With respect to Southern Company's future operating results and consolidated balance sheet.subsidiary's investments in leveraged leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.
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Item 1B. | UNRESOLVED STAFF COMMENTS. |
None.
Item 2. PROPERTIES
Electric
Electric Properties
The traditional operatingelectric operating companies, Southern Power, and SEGCO, at December 31, 2015,2017, owned and/or operated 33 hydroelectric generating stations, 3129 fossil fuel generating stations, three nuclear generating stations, 1315 combined cycle/cogeneration stations, 1635 solar facilities, oneeight wind facility,facilities, one biomass facility, and one landfill gas facility. The amounts of capacity for each company, as of December 31, 2015,2017, are shown in the table below.
| | Generating Station | Location | Nameplate Capacity (1) |
| | Location | Nameplate Capacity (1) |
| |
| | (KWs) |
| | | (KWs) |
| |
FOSSIL STEAM | | | | |
Gadsden | Gadsden, AL | 120,000 |
| | Gadsden, AL | 120,000 |
| |
Gorgas | Jasper, AL | 1,021,250 |
| (2 | ) | Jasper, AL | 1,021,250 |
| |
Barry | Mobile, AL | 1,300,000 |
| (2 | ) | Mobile, AL | 1,300,000 |
| |
Greene County | Demopolis, AL | 300,000 |
| (3 | ) | Demopolis, AL | 300,000 |
| (2 | ) |
Gaston Unit 5 | Wilsonville, AL | 880,000 |
| | Wilsonville, AL | 880,000 |
| |
Miller | Birmingham, AL | 2,532,288 |
| (4 | ) | Birmingham, AL | 2,532,288 |
| (3 | ) |
Alabama Power Total | | 6,153,538 |
| | | 6,153,538 |
| |
Bowen | Cartersville, GA | 3,160,000 |
| | Cartersville, GA | 3,160,000 |
| |
Hammond | Rome, GA | 800,000 |
| | Rome, GA | 800,000 |
| |
McIntosh | Effingham County, GA | 163,117 |
| | Effingham County, GA | 163,117 |
| |
Mitchell | Albany, GA | 125,000 |
| (5 | ) | |
Scherer | Macon, GA | 750,924 |
| (6 | ) | Macon, GA | 750,924 |
| (4 | ) |
Wansley | Carrollton, GA | 925,550 |
| (7 | ) | Carrollton, GA | 925,550 |
| (5 | ) |
Yates | Newnan, GA | 700,000 |
| | Newnan, GA | 700,000 |
| |
Georgia Power Total | | 6,624,591 |
| | | 6,499,591 |
| |
Crist | Pensacola, FL | 970,000 |
| | Pensacola, FL | 970,000 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (8 | ) | Pascagoula, MS | 500,000 |
| (6 | ) |
Lansing Smith | Panama City, FL | 305,000 |
| (9 | ) | |
Scherer Unit 3 | Macon, GA | 204,500 |
| (6 | ) | Macon, GA | 204,500 |
| (4 | ) |
Gulf Power Total | | 1,979,500 |
| | | 1,674,500 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (8 | ) | Pascagoula, MS | 500,000 |
| (6 | ) |
Greene County | Demopolis, AL | 200,000 |
| (3 | ) | Demopolis, AL | 200,000 |
| (2 | ) |
Sweatt | Meridian, MS | 80,000 |
| (10 | ) | |
Watson | Gulfport, MS | 862,000 |
| (10 | ) | Gulfport, MS | 862,000 |
| |
Mississippi Power Total | | 1,642,000 |
| | | 1,562,000 |
| |
Gaston Units 1-4 | Wilsonville, AL | | Wilsonville, AL | |
SEGCO Total | | 1,000,000 |
| (11 | ) | | 1,000,000 |
| (7 | ) |
Total Fossil Steam | | 17,399,629 |
| | | 16,889,629 |
| |
IGCC | | | |
Kemper County/Ratcliffe | Kemper County, MS | | (12 | ) | |
Mississippi Power Total | | 622,906 |
| | |
NUCLEAR STEAM | | | |
Farley | | Dothan, AL | |
Alabama Power Total | | | 1,720,000 |
| |
Hatch | | Baxley, GA | 899,612 |
| (8 | ) |
Vogtle Units 1 and 2 | | Augusta, GA | 1,060,240 |
| (9 | ) |
Georgia Power Total | | | 1,959,852 |
| |
Total Nuclear Steam | | | 3,679,852 |
| |
COMBUSTION TURBINES | | | |
Greene County | | Demopolis, AL | |
Alabama Power Total | | | 720,000 |
| |
Boulevard | | Savannah, GA | 19,700 |
| |
| | Generating Station | Location | Nameplate Capacity (1) |
| | Location | Nameplate Capacity (1) |
| |
NUCLEAR STEAM | | | |
Farley | Dothan, AL | | |
Alabama Power Total | | 1,720,000 |
| | |
Hatch | Baxley, GA | 899,612 |
| (13 | ) | |
Vogtle Units 1 and 2 | Augusta, GA | 1,060,240 |
| (14 | ) | |
Georgia Power Total | | 1,959,852 |
| | |
Total Nuclear Steam | | 3,679,852 |
| | |
COMBUSTION TURBINES | | | |
Greene County | Demopolis, AL | | |
Alabama Power Total | | 720,000 |
| | |
Boulevard | Savannah, GA | 19,700 |
| | |
Intercession City | Intercession City, FL | 47,667 |
| (5 | ) | |
Kraft | Port Wentworth, GA | 22,000 |
| (5 | ) | |
McDonough Unit 3 | Atlanta, GA | 78,800 |
| | Atlanta, GA | 78,800 |
| |
McIntosh Units 1 through 8 | Effingham County, GA | 640,000 |
| | Effingham County, GA | 640,000 |
| |
McManus | Brunswick, GA | 481,700 |
| | Brunswick, GA | 481,700 |
| |
Mitchell | Albany, GA | 78,800 |
| (5 | ) | |
Robins | Warner Robins, GA | 158,400 |
| | Warner Robins, GA | 158,400 |
| |
Wansley | Carrollton, GA | 26,322 |
| (7 | ) | Carrollton, GA | 26,322 |
| (5 | ) |
Wilson | Augusta, GA | 354,100 |
| | Augusta, GA | 354,100 |
| |
Georgia Power Total | | 1,907,489 |
| | | 1,759,022 |
| |
Lansing Smith Unit A | Panama City, FL | 39,400 |
| | Southport, FL | 39,400 |
| |
Pea Ridge Units 1 through 3 | Pea Ridge, FL | 15,000 |
| | Pea Ridge, FL | 15,000 |
| |
Gulf Power Total | | 54,400 |
| | | 54,400 |
| |
Chevron Cogenerating Station | Pascagoula, MS | 147,292 |
| (15 | ) | Pascagoula, MS | 147,292 |
| (10 | ) |
Sweatt | Meridian, MS | 39,400 |
| | Meridian, MS | 39,400 |
| |
Watson | Gulfport, MS | 39,360 |
| | Gulfport, MS | 39,360 |
| |
Mississippi Power Total | | 226,052 |
| | | 226,052 |
| |
Addison (formerly West Georgia) | Thomaston, GA | 668,800 |
| | |
Addison | | Thomaston, GA | 668,800 |
| |
Cleveland County | Cleveland County, NC | 720,000 |
| | Cleveland County, NC | 720,000 |
| |
Dahlberg | Jackson County, GA | 756,000 |
| | Jackson County, GA | 756,000 |
| |
Oleander | Cocoa, FL | 791,301 |
| | Cocoa, FL | 791,301 |
| |
Rowan | Salisbury, NC | 455,250 |
| | Salisbury, NC | 455,250 |
| |
Southern Power Total | | 3,391,351 |
| | | 3,391,351 |
| |
Gaston (SEGCO) | Wilsonville, AL | 19,680 |
| (11 | ) | Wilsonville, AL | 19,680 |
| (7 | ) |
Total Combustion Turbines | | 6,318,972 |
| | | 6,170,505 |
| |
COGENERATION | | | | |
Washington County | Washington County, AL | 123,428 |
| | Washington County, AL | 123,428 |
| |
GE Plastics Project | Burkeville, AL | 104,800 |
| | |
Lowndes County | | Burkeville, AL | 104,800 |
| |
Theodore | Theodore, AL | 236,418 |
| | Theodore, AL | 236,418 |
| |
Total Cogeneration | | 464,646 |
| | |
Alabama Power Total | | | 464,646 |
| |
COMBINED CYCLE | | | |
Barry | | Mobile, AL | |
Alabama Power Total | | | 1,070,424 |
| |
McIntosh Units 10&11 | | Effingham County, GA | 1,318,920 |
| |
McDonough-Atkinson Units 4 through 6 | | Atlanta, GA | 2,520,000 |
| |
Georgia Power Total | | | 3,838,920 |
| |
Lansing Smith Unit 3 | | Southport, FL | |
Gulf Power Total | | | 545,500 |
| |
| | Generating Station | Location | Nameplate Capacity (1) |
| | Location | Nameplate Capacity (1) |
| |
COMBINED CYCLE | | | |
Barry | Mobile, AL | | |
Alabama Power Total | | 1,070,424 |
| | |
McIntosh Units 10&11 | Effingham County, GA | 1,318,920 |
| | |
McDonough-Atkinson Units 4 through 6 | Atlanta, GA | 2,520,000 |
| | |
Georgia Power Total | | 3,838,920 |
| | |
Smith | Lynn Haven, FL | | |
Gulf Power Total | | 545,500 |
| | |
Daniel | Pascagoula, MS | | Pascagoula, MS | 1,070,424 |
| |
Kemper County/Ratcliffe | | Kemper County, MS | 769,898 |
| (11) |
|
Mississippi Power Total | | 1,070,424 |
| | | 1,840,322 |
| |
Franklin | Smiths, AL | 1,857,820 |
| | Smiths, AL | 1,857,820 |
| |
Harris | Autaugaville, AL | 1,318,920 |
| | Autaugaville, AL | 1,318,920 |
| |
Mankato | | Mankato, MN | 375,000 |
| |
Rowan | Salisbury, NC | 530,550 |
| | Salisbury, NC | 530,550 |
| |
Stanton Unit A | Orlando, FL | 428,649 |
| (16 | ) | Orlando, FL | 428,649 |
| (12 | ) |
Wansley | Carrollton, GA | 1,073,000 |
| | Carrollton, GA | 1,073,000 |
| |
Southern Power Total | | 5,208,939 |
| | | 5,583,939 |
| |
Total Combined Cycle | | 11,734,207 |
| | | 12,879,105 |
| |
HYDROELECTRIC FACILITIES | | | | |
Bankhead | Holt, AL | 53,985 |
| | Holt, AL | 53,985 |
| |
Bouldin | Wetumpka, AL | 225,000 |
| | Wetumpka, AL | 225,000 |
| |
Harris | Wedowee, AL | 132,000 |
| | Wedowee, AL | 132,000 |
| |
Henry | Ohatchee, AL | 72,900 |
| | Ohatchee, AL | 72,900 |
| |
Holt | Holt, AL | 46,944 |
| | Holt, AL | 46,944 |
| |
Jordan | Wetumpka, AL | 100,000 |
| | Wetumpka, AL | 100,000 |
| |
Lay | Clanton, AL | 177,000 |
| | Clanton, AL | 177,000 |
| |
Lewis Smith | Jasper, AL | 157,500 |
| | Jasper, AL | 157,500 |
| |
Logan Martin | Vincent, AL | 135,000 |
| | Vincent, AL | 135,000 |
| |
Martin | Dadeville, AL | 182,000 |
| | Dadeville, AL | 182,000 |
| |
Mitchell | Verbena, AL | 170,000 |
| | Verbena, AL | 170,000 |
| |
Thurlow | Tallassee, AL | 81,000 |
| | Tallassee, AL | 81,000 |
| |
Weiss | Leesburg, AL | 87,750 |
| | Leesburg, AL | 87,750 |
| |
Yates | Tallassee, AL | 47,000 |
| | Tallassee, AL | 47,000 |
| |
Alabama Power Total | | 1,668,079 |
| | | 1,668,079 |
| |
Bartletts Ferry | Columbus, GA | 173,000 |
| | Columbus, GA | 173,000 |
| |
Goat Rock | Columbus, GA | 38,600 |
| | Columbus, GA | 38,600 |
| |
Lloyd Shoals | Jackson, GA | 14,400 |
| | Jackson, GA | 14,400 |
| |
Morgan Falls | Atlanta, GA | 16,800 |
| | Atlanta, GA | 16,800 |
| |
North Highlands | Columbus, GA | 29,600 |
| | Columbus, GA | 29,600 |
| |
Oliver Dam | Columbus, GA | 60,000 |
| | Columbus, GA | 60,000 |
| |
Rocky Mountain | Rome, GA | 215,256 |
| (17 | ) | Rome, GA | 215,256 |
| (13 | ) |
Sinclair Dam | Milledgeville, GA | 45,000 |
| | Milledgeville, GA | 45,000 |
| |
Tallulah Falls | Clayton, GA | 72,000 |
| | Clayton, GA | 72,000 |
| |
Terrora | Clayton, GA | 16,000 |
| | Clayton, GA | 16,000 |
| |
Tugalo | Clayton, GA | 45,000 |
| | Clayton, GA | 45,000 |
| |
Wallace Dam | Eatonton, GA | 321,300 |
| | Eatonton, GA | 321,300 |
| |
Yonah | Toccoa, GA | 22,500 |
| | Toccoa, GA | 22,500 |
| |
6 Other Plants | Various Georgia Cities | 18,080 |
| | Various Georgia locations | 18,080 |
| |
Georgia Power Total | | | 1,087,536 |
| |
Total Hydroelectric Facilities | | | 2,755,615 |
| |
| | Generating Station | Location | Nameplate Capacity (1) |
| | Location | Nameplate Capacity (1) |
| |
Georgia Power Total | | 1,087,536 |
| | |
Total Hydroelectric Facilities | | 2,755,615 |
| | |
RENEWABLE SOURCES: | | | | |
SOLAR FACILITIES | | | | |
Fort Benning | Columbus, GA | 30,000 |
| | Columbus, GA | 30,000 |
| |
Fort Gordon | | Augusta, GA | 30,000 |
| |
Fort Stewart | | Fort Stewart, GA | 30,000 |
| |
Kings Bay | | Camden County, GA | 30,000 |
| |
Dalton | Dalton, GA | 6,305 |
| | Dalton, GA | 6,012 |
| |
3 Other Plants | | Various Georgia locations | 2,984 |
| |
Georgia Power Total | | 36,305 |
| | | 128,996 |
| |
Adobe | Kern County, CA | 20,000 |
| | Kern County, CA | 20,000 |
| |
Apex | North Las Vegas, NV | 20,000 |
| | North Las Vegas, NV | 20,000 |
| |
Boulder I | | Clark County, NV | 100,000 |
| (14 | ) |
Butler | | Taylor County, GA | 103,700 |
| |
Butler Solar Farm | | Taylor County, GA | 22,000 |
| |
Calipatria | | Imperial County, CA | 20,000 |
| |
Campo Verde | Imperial County, CA | 147,420 |
| | Imperial County, CA | 147,420 |
| |
Cimarron | Springer, NM | 30,640 |
| | Springer, NM | 30,640 |
| |
Decatur County | Decatur County, GA | 20,000 |
| | Decatur County, GA | 20,000 |
| |
Decatur Parkway | Decatur County, GA | 84,000 |
| | Decatur County, GA | 84,000 |
| |
Desert Stateline | San Bernadino County, CA | 110,120 |
| (18) | San Bernadino County, CA | 299,900 |
| (14 | ) |
East Pecos | | Pecos County, TX | 120,000 |
| |
Garland | | Kern County, CA | 205,130 |
| (14 | ) |
Granville | Oxford, NC | 2,500 |
| | Oxford, NC | 2,500 |
| |
Henrietta | | Kings County, CA | 102,000 |
| (14 | ) |
Imperial Valley | Imperial County, CA | 163,200 |
| | Imperial County, CA | 163,200 |
| (14 | ) |
Lamesa | | Dawson County, TX | 102,000 |
| |
Lost Hills - Blackwell | Kern County, CA | 33,440 |
| | Kern County, CA | 33,440 |
| (14 | ) |
Macho Springs | Luna County, NM | 55,000 |
| | Luna County, NM | 55,000 |
| |
Morelos del Sol | Kern County, CA | 15,000 |
| | Kern County, CA | 15,000 |
| |
North Star | Fresno County, CA | 61,600 |
| | Fresno County, CA | 61,600 |
| (14 | ) |
Pawpaw | | Taylor County, GA | 30,480 |
| |
Roserock | | Pecos County, TX | 160,000 |
| (14 | ) |
Rutherford | | Rutherford County, NC | 74,800 |
| |
Sandhills | | Taylor County, GA | 146,890 |
| |
Spectrum | Clark County, NV | 30,240 |
| | Clark County, NV | 30,240 |
| |
Tranquillity | | Fresno County, CA | 205,300 |
| (14 | ) |
Southern Power Total | | 793,160 |
| (19 | ) | | 2,375,240 |
| (15 | ) |
Total Solar | | 829,465 |
| | | 2,504,236 |
| |
WIND FACILITY | | | |
Kay Wind | Kay County, OK | | |
Southern Power Total | | 299,000 |
| | |
LANDFILL GAS FACILITY | | | |
Perdido | Escambia County, FL | | |
Gulf Power Total | | 3,200 |
| | |
BIOMASS FACILITY | | | |
Nacogdoches | Sacul, TX | | |
Southern Power Total | | 115,500 |
| | |
Total Generating Capacity | | 44,222,992 |
| | |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
WIND FACILITIES | | | |
Bethel | Castro County, TX | 276,000 |
| |
Grant Plains | Grant County, OK | 147,200 |
| |
Grant Wind | Grant County, OK | 151,800 |
| |
Kay Wind | Kay County, OK | 299,000 |
| |
Passadumkeag | Penobscot County, ME | 42,900 |
| |
Salt Fork | Donley & Gray Counties TX | 174,000 |
| |
Tyler Bluff | Cooke County, TX | 125,580 |
| |
Wake Wind | Crosby & Floyd Counties, TX | 257,250 |
| (14 | ) |
Southern Power Total | | 1,473,730 |
| |
LANDFILL GAS FACILITY | | | |
Perdido | Escambia County, FL | | |
Gulf Power Total | | 3,200 |
| |
BIOMASS FACILITY | | | |
Nacogdoches | Sacul, TX | | |
Southern Power Total | | 115,500 |
| |
Total Generating Capacity | | 46,936,018 |
| |
Notes:
|
| |
(1) | See "Jointly-Owned Facilities" herein for additional information. |
(2) | In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In August 2015, Alabama Power retired Plant Barry Unit 3 (225 MWs) and it is no longer available for generation. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power in Item 7 herein. See also Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" and "Retail Regulatory – Environmental Accounting Order," respectively, in Item 8 herein. |
|
| |
(3) | Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively. Alabama Power and Mississippi Power expect to cease using coal and begin operating these units solely on natural gas by April 2016. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" of Southern Company, MANAGEMENT'S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - "Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power, and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 herein. See also Note 3 to the financial statements of Southern Company, Alabama Power, and Mississippi Power under "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order," "Retail Regulatory Matters – Environmental Accounting Order," and "Retail Regulatory Matters – Environmental Compliance Overview Plan," respectively, in Item 8 herein. |
(4)(3) | Capacity shown is Alabama Power's portion (91.84%(95.92%) of total plant capacity. |
(5) | On January 29, 2016, Georgia Power filed its triennial IRP (2016 IRP). The filing included a request to decertify Plant Mitchell Units 3, 4A, and 4B (217MWs) and Plant Kraft Unit 1 (17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that Georgia Power exercised its contractual option to sell its ownership interest in the Intercession City unit to Duke Energy Florida, Inc. contingent upon regulatory approvals. The ultimate outcome of this matter cannot be determined at this time. Capacity shown represents 33% of the total plant capacity of 143,000 KWs. Georgia Power owns a 33% interest in the unit with 100% use of the unit from June through September. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 herein. See also Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory – Integrated Resource Plan," respectively, in Item 8 herein. |
(6)(4) | Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3. |
(7)(5) | Capacity shown is Georgia Power's portion (53.5%) of total plant capacity. |
(8)(6) | Represents 50% of Plant Daniel Units 1 and 2, which are owned as tenants in common by Gulf Power and Mississippi Power. |
(9) | Gulf Power intends to retire Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. |
(10) | Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source at Plant Sweatt Units 1 and 2 (80 MWs) by December 2018. Mississippi Power also ceased burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and began operating those units solely on natural gas on April 16, 2015. |
(11)(7) | SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information. |
(12) | Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The Kemper IGCC is expected to have an output capacity of 582 MW. |
(13)(8) | Capacity shown is Georgia Power's portion (50.1%) of total plant capacity. |
(14)(9) | Capacity shown is Georgia Power's portion (45.7%) of total plant capacity. |
(15)(10) | Generation is dedicated to a single industrial customer. |
(16)(11) | The capacity shown is the gross capacity using natural gas fuel without supplemental firing. |
(12) | Capacity shown is Southern Power's portion (65%) of total plant capacity. |
(17)(13) | Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant. |
(18)(14) | The first three phases (110 MW) were placed in service in December 2015. Phases four and five were placed in service in January and February 2016, respectively. The remaining three phases are expected to be placed in service during 2016, bringing the facility's total capacity to approximately 300 MW. |
(19) | Each facility is owned by Southern Power total solarthrough a majority-owned subsidiary (90.1% Wake Wind, 66% Desert Stateline, and 51% for each of the following facilities: Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills-Blackwell, North Star, Roserock, and Tranquillity). The capacity shown in the table is 100% of the nameplate capacity for eachthe respective facility. When taking into consideration |
(15) | Southern Power's 90%Power is pursuing the sale of a 33% equity interest in STR and 51% equity interest in SRP's seven partnerships,a newly-formed holding company that owns substantially all of Southern Power's equity portionsolar assets, which, if successful, is expected to close in the middle of the total nameplate capacity from all generating sources is 9,595 MW. See Note 2 to the financial statements of Southern Power in Item 8 herein and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 herein for additional information.2018. |
Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition.condition, and suitable for their intended purpose.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is
paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2015,2017, the unamortized portion of this cost was approximately $14$13 million.
In conjunction with the Kemper IGCC, Mississippi Power owns a lignite mine and equipment andthat were intended to provide fuel for the Kemper IGCC. Mississippi Power also has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site in Kemper County.County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in June 2013 with2013. Liberty Fuels Company, LLC, the capital costoperator of the mine, has a legal obligation to perform mine reclamation and equipment totaling approximately $313 million as of December 31, 2015.Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation activities to begin in 2018. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle"Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle"Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" in Item 8 herein for additional information on the lignite mine.
In 2015,2018, Mississippi Power will file a reserve margin plan which could impact Mississippi Power's generating stations as well as the generating stations jointly owned by Mississippi Power and other traditional electric operating companies. See BUSINESS in Item 1 herein under "Rate Matters – Integrated Resource Planning – Mississippi Power" for additional information.
In 2017, the maximum demand on the traditional electric operating companies, Southern Power, and SEGCO was 36,794,00034,874,000 KWs and occurred on January 8, 2015.August 17, 2017. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power, and SEGCO in 20152017 was 33.2%30.8%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information.
Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power at December 31, 20152017 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Percentage Ownership |
| | Total Capacity | | Alabama Power | | Power South | | Georgia Power | | OPC | | MEAG Power | | Dalton | | Duke Energy Florida | | Southern Power | | OUC | | FMPA | | KUA |
| | (MWs) | | | | | | | | | | | | | | | | | | | | | | |
Plant Miller Units 1 and 2 | | 1,320 |
| | 91.8 | % | | 8.2 | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % | | — | % |
Plant Hatch | | 1,796 |
| | — |
| | — |
| | 50.1 |
| | 30.0 |
| | 17.7 |
| | 2.2 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Plant Vogtle Units 1 and 2 | | 2,320 |
| | — |
| | — |
| | 45.7 |
| | 30.0 |
| | 22.7 |
| | 1.6 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Plant Scherer Units 1 and 2 | | 1,636 |
| | — |
| | — |
| | 8.4 |
| | 60.0 |
| | 30.2 |
| | 1.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Plant Wansley | | 1,779 |
| | — |
| | — |
| | 53.5 |
| | 30.0 |
| | 15.1 |
| | 1.4 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rocky Mountain | | 848 |
| | — |
| | — |
| | 25.4 |
| | 74.6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Intercession City, FL* | | 143 |
| | — |
| | — |
| | 33.3 |
| | — |
| | — |
| | — |
| | 66.7 |
| | — |
| | — |
| | — |
| | — |
|
Plant Stanton A | | 660 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 65.0 |
| | 28.0 |
| | 3.5 |
| | 3.5 |
|
|
| |
* | Subsequent to December 31, 2015, Georgia Power exercised its contractual option to sell its ownership interest to Duke Energy Florida, Inc. contingent on regulatory approvals. The ultimate outcome of this matter cannot be determined at this time. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Percentage Ownership |
| | Total Capacity | | Alabama Power | | Power South | | Georgia Power | | OPC | | MEAG Power | | Dalton | | | Southern Power | | OUC | | FMPA | | KUA |
| | (MWs) | | | | | | | | | | | | | | | | | | | | | |
Plant Miller Units 1 and 2 | | 1,320 |
| | 91.8 | % | | 8.2 | % | | — | % | | — | % | | — | % | | — | % | | | — | % | | — | % | | — | % | | — | % |
Plant Hatch | | 1,796 |
| | — |
| | — |
| | 50.1 |
| | 30.0 |
| | 17.7 |
| | 2.2 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Vogtle Units 1 and 2 | | 2,320 |
| | — |
| | — |
| | 45.7 |
| | 30.0 |
| | 22.7 |
| | 1.6 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Scherer Units 1 and 2 | | 1,636 |
| | — |
| | — |
| | 8.4 |
| | 60.0 |
| | 30.2 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Wansley | | 1,779 |
| | — |
| | — |
| | 53.5 |
| | 30.0 |
| | 15.1 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Rocky Mountain | | 848 |
| | — |
| | — |
| | 25.4 |
| | 74.6 |
| | — |
| | — |
| | | — |
| | — |
| | — |
| | — |
|
Plant Stanton A | | 660 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 65.0 |
| | 28.0 |
| | 3.5 |
| | 3.5 |
|
Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain and Intercession City)Mountain) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A. Southern Nuclear operates and provides services to Alabama Power’sPower's and Georgia Power’sPower's nuclear plants.
In addition, Georgia Power has commitments regarding a portion of a 5% interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC's disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power's statements of income in Item 8 herein. Also see Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 herein for additional information.
Georgia Power is currently constructing
Construction continues on Plant Vogtle Units 3 and 4, which will beare jointly owned by Georgia Power, Dalton, OPC, and MEAG Powerthe Vogtle Owners (with each owner holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear"Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein.
Titles to Property
The traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants (other than certain pollution control facilities and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the (1) liens pursuant to pollution control revenue bonds of Gulf Power on specific pollution control facilities at Plant Daniel, (2) liens pursuant to the assumption of debt obligations by Mississippi Power in connection with the acquisition of Plant Daniel Units 3 and 4, (3) liens pursuant to the agreements entered into with Mississippi Power's largest customer, Chevron Products Company (Chevron), on October 4, 2017, on the co-generation assets located at the Chevron refinery, (4) liens associated with Georgia Power’sPower's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power’sPower's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power’sPower's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4, and (4)(5) liens associated with credit agreements entered intotwo PPAs assumed as part of the acquisition of the Mankato project in October 2016 by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power Company. See Note 6 to the financial statements of Southern Company, Georgia Power, Gulf Power, Mississippi Power, and MississippiSouthern Power under "Assets Subject to Lien," Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings," and Note 6 to the financial statements of Southern Company and Mississippi Power under "Plant Daniel Revenue Bonds," and Note 6 to the financial statements of Southern Power Company under "Bank Credit Arrangements – Subsidiary Facilities"Bonds" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.
Natural Gas
Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 6 to the financial statements of Southern Company Gas under "Long-Term Debt – First Mortgage Bonds" in Item 8 herein for additional information.
Distribution and Transmission Mains – Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2017, Southern Company Gas' gas distribution operations segment owned approximately 82,000 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.
Storage Assets – Gas Distribution Operations– Southern Company Gas owns and operates eight underground natural gas storage facilities in Illinois with a total inventory capacity of approximately 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.
Southern Company Gas also has five liquefied natural gas (LNG) plants located in Georgia, New Jersey, and Tennessee with total LNG storage capacity of approximately 7.6 Bcf. In addition, Southern Company Gas owns one propane storage facility in Virginia with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.
Storage Assets – All Other– Southern Company Gas subsidiaries own three high-deliverability natural gas storage and hub facilities that are operated by the gas midstream operations segment. Jefferson Island Storage & Hub, LLC operates a storage facility in Louisiana consisting of two salt dome gas storage caverns. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California. In addition, Southern Company Gas has a LNG facility in Alabama that produces LNG for Pivotal LNG, Inc. to support its business of selling LNG as a substitute fuel in various markets.
In August 2017, in connection with an ongoing integrity project into the salt dome gas storage caverns in Louisiana, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note 3 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
Jointly-Owned Properties– Southern Company Gas' gas midstream operations segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia that was placed in service on August 1, 2017. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 4 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
(1) Georgia Power et al. v. Westinghouse and Stone & Webster (United States District Court for the Southern District of Georgia Augusta Division)
Stone & Webster and Westinghouse v. Georgia Power et al. (United States District Court for the District of Columbia)
See Note 3 to the financial statements of Southern Company and Georgia Power under "Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for information.
(2) Environmental Remediation
See Note 3 to the financial statements of Southern Company, Georgia Power, and Gulf Power under "Environmental Matters – Environmental Remediation" in Item 8 herein for information related to environmental remediation.
See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of additional legal and administrative proceedings discussed therein.
| |
Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2015.2017.
Thomas A. Fanning
Chairman, President, and Chief Executive Officer and Director
Age 5860
Elected in 2003. Chairman and Chief Executive Officer and Director since December 2010 and President since August 2010.
Art P. Beattie
Executive Vice President and Chief Financial Officer
Age 6163
Elected in 2010. Executive Vice President and Chief Financial Officer since August 2010.
W. Paul Bowers
Executive Vice President
Age 5961
Elected in 2001. Executive Vice President since February 2008 and Chief Executive Officer, President, and Director of Georgia Power since January 2011. Chairman of Georgia Power's Board of Directors since May 2014.
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer of Gulf Power
Age 4648
Elected in 2012. Elected Chairman in July 2015 and President, Chief Executive Officer, and Director of Gulf Power since July 2012. Previously served as Senior Vice President and Chief Production Officer of Georgia Power from August 2010 through June 2012.
Mark A. Crosswhite
Executive Vice President
Age 5355
Elected in 2010. Executive Vice President since December 2010July 2012 and President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 20142014.
Andrew W. Evans
Executive Vice President
Age 51
Elected in July 2016. Executive Vice President since July 2016. President of Southern Company Gas since May 2015 and President, Chief Executive Officer and DirectorChairman of Gulf PowerSouthern Company Gas' Board of Directors since January 2016. Previously served as Chief Operating Officer of Southern Company Gas from January 2011May 2015 through June 2012.December 2015 and Executive Vice President and Chief Financial Officer of Southern Company Gas from May 2006 through May 2015.
Kimberly S. Greene
Executive Vice President
Age 4951
Elected in 2013. Executive Vice President and Chief Operating Officer since March 2014. Director of Southern Company Gas since July 2016. Previously served as President and Chief Executive Officer of SCS from April 2013 to February 2014. Before rejoining Southern Company, Ms. Greene previously served at Tennessee Valley Authority in a number of positions, most recently as Executive Vice President and Chief Generation Officer from 2011 through April 2013, and Group President of Strategy and External Relations from 2010 through 2011.2013.
James Y. Kerr II
Executive Vice President and General Counsel
Age 5153
Elected in 2014. Also serves as Chief Compliance Officer. Before joining Southern Company, Mr. Kerr was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC from 2008 through February 2014.
Stephen E. Kuczynski
Chairman, President, and Chief Executive Officer of Southern Nuclear
Age 5355
Elected in 2011. Chairman, President, and Chief Executive Officer of Southern Nuclear since July 2011. Before joining Southern Company, Mr. Kuczynski served at Exelon Corporation as the Senior Vice President
Mark S. Lantrip
Executive Vice President
Age 6163
Elected in 2014. Chairman, President, and Chief Executive Officer of SCS since March 2014. Previously served as Treasurer of Southern Company from October 2007 to February 2014 and Executive Vice President of SCS from November 2010 to March 2014.
Nancy E. Sykes
I-43
Age 49
Elected in 2016. Also serves as Chief Human Resources Officer of SCS. Before joining Southern Company, Ms. Sykes served as vice president and chief human resources officer at United States Steel Corporation from May 2015 to Financial StatementsNovember 2016. Previously served as Vice President, Human Resources Asia-Pacific at Goodyear Tire and Rubber Company from October 2012 until May 2015.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer of Mississippi Power
Age 5153
Elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016. Previously served as Executive Vice President of Mississippi Power from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015, and Vice President of Georgia Power from February 2007 to December 2011.2015.
Christopher C. Womack
Executive Vice President
Age 5759
Elected in 2008. Executive Vice President and President of External Affairs since January 2009.
The officers of Southern Company were elected at the first meeting of the directors following the last annual meeting of stockholders held on May 27, 2015,24, 2017, for a term of one year or until their successors are elected and have qualified.
EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2015.2017.
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer and Director
Age 5355
Elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014 and President, Chief Executive Officer, and Director of Gulf Power from January 2011 through June 2012.2014.
Greg J. Barker (1)
Executive Vice President
Age 5254
Elected in 2016. Executive Vice President for Customer Services since February 22, 2016. Previously served as Senior Vice President of Marketing and Economic Development from April 2012 to February 2016 and Senior Vice President of Business Development and Customer Support from July 2010 to April 2012.2016.
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
Age 5658
Elected in 2010. Executive Vice President, Chief Financial Officer, and Treasurer since August 2010.
Zeke W. Smith
Executive Vice President
Age 5658
Elected in 2010. Executive Vice President of External Affairs since November 2010.
Steven R. Spencer (1)
Executive Vice President
Age 60
Elected in 2001. Executive Vice President of the Customer Service Organization since February 2008.
James P. Heilbron
Senior Vice President and Senior Production Officer
Age 4446
Elected in 2013. Senior Vice President and Senior Production Officer since March 2013. Previously served as Senior Vice President and Senior Production Officer of Southern Power Company from July 2010 to February 2013.
(1) On February 17, 2016, Mr. Spencer resigned the role of ExecutiveR. Scott Moore
Senior Vice President
Age 50
Elected in 2017. Senior Vice President effective April 1, 2016. Mr. Greg Barker was elected to the role of ExecutivePower Delivery since May 2017. Previously served as Vice President for Customer Services, effective February 22, 2016.of Transmission from August 2012 to May 2017.
The officers of Alabama Power were elected for at the meeting of the directors held on April 24, 201528, 2017 for a term of one year or until their successors are elected and have qualified, except for Mr. BarkerMoore, whose election as ExecutiveSenior Vice President was effective February 22, 2016.May 20, 2017.
EXECUTIVE OFFICERS OF GEORGIA POWER
(Identification of executive officers of Georgia Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2015.
W. Paul Bowers
Chairman, President, Chief Executive Officer, and Director
Age 59
Elected in 2010. Chief Executive Officer, President, and Director since December 2010 and Chief Operating Officer of Georgia Power from August 2010 to December 2010. Chairman of Georgia Power's Board of Directors since May 2014.
W. Craig Barrs
Executive Vice President
Age 58
Elected in 2008. Executive Vice President of Customer Service and Operations since May 2015. Previously served as Executive Vice President of External Affairs from January 2010 to May 2015.
W. Ron Hinson
Executive Vice President, Chief Financial Officer, Treasurer, and Corporate Secretary
Age 59
Elected in 2013. Executive Vice President, Chief Financial Officer, and Treasurer since March 2013 and Corporate Secretary and Chief Compliance Officer since January 2016. Also, served as Comptroller from March 2013 until January 2014. Previously served as Comptroller and Chief Accounting Officer of Southern Company, as well as Senior Vice President and Comptroller of SCS from March 2006 to March 2013.
Christopher P. Cummiskey
Executive Vice President
Age 41
Elected in 2015. Executive Vice President of External Affairs since May 2015. Previously served as Chief Commercial Officer of Southern Power from October 2013 to May 2015 and Commissioner of the Georgia Department of Economic Development from January 2011 to October 2013.
John L. Pemberton
Senior Vice President and Senior Production Officer
Age 47
Elected in 2012. Senior Vice President and Senior Production Officer since July 2012. Previously served as Senior Vice President and General Counsel for SCS and Southern Nuclear from June 2010 to July 2012.
The officers of Georgia Power were elected at the meeting of the directors held on May 20, 2015 for a term of one year or until their successors are elected and have qualified, except for Mr. Hinson, whose election as Corporate Secretary was effective January 1, 2016.
EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2015.2017.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer and Director
Age 5153
Elected in 2015. President since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board since August 2016. Previously served as Executive Vice President from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015, and Vice President of Georgia Power from February 2007 to December 2011.2015.
John W. Atherton
Vice President
Age 5557
Elected in 2004. Vice President of Corporate Services and Community Relations since October 2012. Previously served as Vice President of External Affairs from January 2005 until October 2012.
A. Nicole Faulk
Vice President
Age 4244
Elected in 2015. Vice President of Customer Services Organization effective April 2015. Previously served as Region Vice President for the West Region of Georgia Power from March 2015 through April 2015 and Region Manager for the Metro West Region of Georgia Power from December 2011 to March 2015, and a director of Nuclear Development at Southern Nuclear from March 2010 to December 2011.2015.
Moses H. Feagin
Vice President, Treasurer, and Chief Financial Officer
Age 5153
Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 2010.
R. Allen Reaves, Jr.
Vice President
Age 5658
Elected in 2010. Vice President and Senior Production Officer since August 2010.
Billy F. Thornton
Vice President
Age 5557
Elected in 2012. Vice President of External Affairs since October 2012. Previously served as Director of External Affairs from October 2011 until October 2012, Director of Marketing from March 2011 through October 2011, and Major Account Sales Manager from June 2006 to March 2011.
Emile J. Troxclair, III
Vice President
Age 58
Elected in 2014. Vice President of Kemper Development since January 2015. Previously served as Vice President of Gasification for Lummus Technology Inc. from May 2013 through April 2014, Manager of E-Gas Technology for Phillips 66 from 2012 to May 2013, and Manager of E-Gas Technology for ConocoPhillips from 2003 to 2012.
The officers of Mississippi Power were elected at the meeting of the directors held on April 28, 2015May 1, 2017 for a term of one year or until their successors are elected and have qualified, except for Mr. Wilson, whose election as President was effective October 19, 2015 and election as Chief Executive Officer was effective January 1, 2016.qualified.
PART II
| |
Item 5. | MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
(a)(1) The common stock of Southern Company is listed and traded on the NYSE. The common stock is also traded on regional exchanges across the U.S. The high and low stock prices as reported on the NYSE for each quarter of the past two years were as follows:
| | | | High | | Low | | High | | Low |
2015 | | | | | |
2017 | | | | | |
First Quarter | | $ | 53.16 |
| | $ | 43.55 |
| | $ | 51.47 |
| | $ | 47.57 |
|
Second Quarter | | 45.44 |
| | 41.40 |
| | 51.97 |
| | 47.87 |
|
Third Quarter | | 46.84 |
| | 41.81 |
| | 50.80 |
| | 46.71 |
|
Fourth Quarter | | 47.50 |
| | 43.38 |
| | 53.51 |
| | 47.92 |
|
2014 | | | | | |
2016 | | | | | |
First Quarter | | $ | 44.00 |
| | $ | 40.27 |
| | $ | 51.73 |
| | $ | 46.00 |
|
Second Quarter | | 46.81 |
| | 42.55 |
| | 53.64 |
| | 47.62 |
|
Third Quarter | | 45.47 |
| | 41.87 |
| | 54.64 |
| | 50.00 |
|
Fourth Quarter | | 51.28 |
| | 43.55 |
| | 52.23 |
| | 46.20 |
|
There is no market for the other registrants' common stock, all of which is owned by Southern Company.
(a)(2) Number of Southern Company's common stockholders of record at January 31, 2016: 131,4582018: 120,413
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrant's common stock are payable at the discretion of their respective board of directors.directors and depend upon earnings, financial condition, and other factors. The dividends on common stock declared by Southern Company, and the traditional electric operating companies (other than Mississippi Power), Southern Power Company, and Southern Company Gas to their stockholder(s) for the past two years are set forth below. No dividends were as follows:declared by Mississippi Power on its common stock in 2016 or 2017. Southern Company Gas' dividends are only shown for periods subsequent to the Merger.
|
| | | | | | | | | | |
Registrant | | Quarter | | 2015 | | 2014 |
| | | | (in thousands) |
Southern Company | | First | | $ | 478,454 |
| | $ | 450,991 |
|
| | Second | | 493,161 |
| | 469,198 |
|
| | Third | | 493,382 |
| | 471,044 |
|
| | Fourth | | 493,884 |
| | 474,428 |
|
Alabama Power | | First | | 142,820 |
| | 137,390 |
|
| | Second | | 142,820 |
| | 137,390 |
|
| | Third | | 142,820 |
| | 137,390 |
|
| | Fourth | | 142,820 |
| | 137,390 |
|
Georgia Power | | First | | 258,570 |
| | 238,400 |
|
| | Second | | 258,570 |
| | 238,400 |
|
| | Third | | 258,570 |
| | 238,400 |
|
| | Fourth | | 258,570 |
| | 238,400 |
|
Gulf Power | | First | | 32,540 |
| | 30,800 |
|
| | Second | | 32,540 |
| | 30,800 |
|
| | Third | | 32,540 |
| | 30,800 |
|
| | Fourth | | 32,540 |
| | 30,800 |
|
Mississippi Power | | First | | — |
| | 54,930 |
|
| | Second | | — |
| | 54,930 |
|
| | Third | | — |
| | 54,930 |
|
| | Fourth | | — |
| | 54,930 |
|
In 2015 and 2014, Southern Power Company paid dividends to Southern Company as follows:
| | Registrant | | Quarter | | 2015 | | 2014 | | Quarter | | 2017 | | 2016 |
| | | | | (in thousands) |
Southern Company | | | First | | $ | 555,791 |
| | $ | 496,718 |
|
| | | Second | | 578,525 |
| | 526,267 |
|
| | | Third | | 581,501 |
| | 529,876 |
|
| | | Fourth | | 584,015 |
| | 551,110 |
|
Alabama Power | | | First | | 178,507 |
| | 191,206 |
|
| | | Second | | 178,507 |
| | 191,206 |
|
| | | Third | | 178,507 |
| | 191,206 |
|
| | | Fourth | | 178,507 |
| | 191,206 |
|
Georgia Power | | | First | | 320,242 |
| | 326,269 |
|
| | | Second | | 320,242 |
| | 326,269 |
|
| | | Third | | 320,242 |
| | 326,269 |
|
| | | Fourth | | 320,242 |
| | 326,269 |
|
Gulf Power | | | First | | 31,250 |
| | 30,017 |
|
| | | Second | | 31,250 |
| | 30,017 |
|
| | | Third | | 31,250 |
| | 30,017 |
|
| | | | (in thousands) | | Fourth | | 71,250 |
| | 30,017 |
|
Southern Power Company | | First | | $ | 32,640 |
| | $ | 32,780 |
| | First | | 79,211 |
| | 68,082 |
|
| | Second | | 32,640 |
| | 32,780 |
| | Second | | 79,211 |
| | 68,082 |
|
| | Third | | 32,640 |
| | 32,780 |
| | Third | | 79,211 |
| | 68,082 |
|
| | Fourth | | 32,640 |
| | 32,780 |
| | Fourth | | 79,211 |
| | 68,082 |
|
Southern Company Gas | | | First | | 110,641 |
| | — |
|
| | | Second | | 110,641 |
| | — |
|
| | | Third | | 110,641 |
| | 62,750 |
|
| | | Fourth | | 110,641 |
| | 62,750 |
|
The dividend paid per share of Southern Company's common stock was 52.50¢56.00¢ for the first quarter 20152017 and 54.25¢58.00¢ each for the second, third, and fourth quarters of 2015.2017. In 2014,2016, Southern Company paid a dividend per share of 50.75¢54.25¢ for the first quarter and 52.50¢56.00¢ each for the second, third, and fourth quarters.
The traditional electric operating companies and Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. The authority of the natural gas distribution utilities to pay dividends to Southern Company Gas is subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates. Additionally, Elizabethtown Gas is restricted by its policy, as established by the New Jersey Board of Public Utilities, to 70% of its quarterly net income it can dividend to Southern Company Gas. Also, as stipulated in the New Jersey Board of Public Utilities' order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade.
(a)(4) Securities authorized for issuance under equity compensation plans.
See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
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Item 6. | SELECTED FINANCIAL DATA |
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Mississippi Power. See "SELECTED FINANCIAL AND OPERATING DATA" | |
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Item 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each of the registrants in Item 7 herein and Note 1 of each of the registrant's financial statements under "Financial Instruments" in Item 8 herein. See also NoteNotes 10 and 11 to the financial statements of Southern Company, Alabama Power, and Georgia
Power, NoteNotes 9 and 10 to the financial statements of Gulf Power, and Mississippi Power, and NoteSouthern Company Gas, and Notes 8 and 9 to the financial statements of Southern Power in Item 8 herein.
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Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO 20152017 FINANCIAL STATEMENTS
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Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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Item 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls Andand Procedures.
As of the end of the period covered by this Annual Report on Form 10-K, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Power Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
(a) Management's Annual Report on Internal Control Over Financial Reporting.
Southern Company's Management's Report on Internal Control Over Financial Reporting is included on page II-8 of this Form 10-K.Alabama Power's Management's Report on Internal Control Over Financial Reporting is included on page II-131 of this
Form 10-K.
Georgia Power's Management's Report on Internal Control Over Financial Reporting is included on page II-208 of this
Form 10-K.
Gulf Power's Management's Report on Internal Control Over Financial Reporting is included on page II-292 of this Form 10-K.
Mississippi Power's Management's Report on Internal Control Over Financial Reporting is included on page II-362 of this Form 10-K.
Southern Power's Management's Report on Internal Control Over Financial Reporting is included on page II-450 of this
Form 10-K. |
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Management's Report on Internal Control Over Financial Reporting | Page |
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(b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Company's independent registered public accounting firm, regarding Southern Company's Internal Control over Financial Reporting is included on page II-9 of this Form 10-K. This report is not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas as these companies are not accelerated filers or large accelerated filers.
(c) Changes in internal control over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Power Company'sCompany Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the fourth quarter 20152017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Power Company'sCompany Gas' internal control over financial reporting.
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Item 9B. | OTHER INFORMATION |
None.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 20152017 Annual Report
The management of The Southern Company (Southern Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 2015.2017.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 2015. Deloitte & Touche LLP's report on Southern Company's internal control over financial reporting2017, which is included herein.
/s/ Thomas A. Fanning
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President and Chief Financial Officer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors and Stockholders of
The Southern Company and Subsidiary Companies
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 20152017 and 2014, and2016, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2015.2017, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2015,2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Commission (COSO).
In our opinion, the financial statements (pages II-64 to II-151) referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting (page II-8). Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, andas well as evaluating the overall presentation of the financial statement presentation.statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements (pages II-52 to II-126) referred to above present fairly, in all material respects, the financial position of Southern Company and Subsidiary Companies as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
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Term | Meaning |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of theMississippi Power's Kemper IGCCCounty energy facility |
2013 ARP | Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
AFUDC | Allowance for funds used during construction |
AGL Resources | AGL Resources Inc. |
Alabama Power | Alabama Power Company |
APAARO | Asset purchase agreementretirement obligation |
ASC | Accounting Standards Codification |
Baseload ActASU | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of MississippiAccounting Standards Update |
Bridge AgreementAtlanta Gas Light | Senior unsecured Bridge Credit Agreement, dated asAtlanta Gas Light Company, a wholly-owned subsidiary of September 30, 2015, among Southern Company the lenders identified therein,Gas |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a joint venture to construct and Citibank, N.A.operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest |
Bechtel | Bechtel Power Corporation |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
COD | Commercial operation date |
Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
Cooperative Energy | Electric cooperative in Mississippi |
CPCN | Certificate of public convenience and necessity |
CWIP | Construction work in progress |
Dalton Pipeline | A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest |
DOE | U.S. Department of Energy |
Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FFB | Federal Financing Bank |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe) |
Interim Assessment Agreement | Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
Kemper IGCC | IGCC facility under construction by Mississippi Power in Kemper County, Mississippi |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
DEFINITIONS
(continued)
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Term | Meaning |
LIFO | Last-in, first-out |
Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
LTSA | Long-term service agreement |
Merger | The merger, effective July 1, 2016, of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company |
Merger Agreement | Agreement with and Plan of Merger, dated as of August 23, 2015, amonginto Southern Company AGL Resources, and Merger Sub |
Merger Sub | AMS Corp., a wholly-owned, direct subsidiary ofGas, with Southern Company Gas continuing as the surviving corporation |
Mirror CWIP | A regulatory liability account for use in mitigating future rate impacts forused by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility, which were subsequently refunded to customers |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MPUS | Mississippi Public Utilities Staff |
MW | Megawatt |
natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Inc., Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) |
NCCR | Georgia Power's Nuclear Construction Cost Recovery |
DEFINITIONS
(continued)
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Term | Meaning |
NDR | Alabama Power's Natural Disaster Reserve |
New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
Plant Vogtle Units 3PennEast Pipeline | PennEast Pipeline Company, LLC, a joint venture to construct and 4operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest |
PowerSecure | Two new nuclear generating units under construction at Georgia Power's Plant VogtlePowerSecure, Inc. |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreementagreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PSC | Public Service Commission |
PTC | Production tax credit |
Rate CNP | Alabama Power's Rate Certificated New Plant |
Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
Rate CNP Environmental | Alabama Power's Rate Certificated New Plant Environmental |
Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Alabama Power's Rate Energy Cost Recovery |
Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
DEFINITIONS
(continued)
SMEPA |
| South Mississippi Electric Power Association |
Term | Meaning |
SO2 | Sulfur dioxide |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | The Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
Toshiba | Toshiba Corporation, parent company of Westinghouse |
Toshiba Guarantee | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
VCM | Vogtle Construction Monitoring |
Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
Vogtle Services Agreement | The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear |
Westinghouse | Westinghouse Electric Company LLC |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 20152017 Annual Report
OVERVIEW
Business Activities
The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businessbusinesses of the Southern Company system isare electricity sales by the traditional electric operating companies and Southern Power.Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. See FUTURE EARNINGS POTENTIAL – "General" herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
Many factors affect the opportunities, challenges, and risks of the Southern Company system's electricity business.and natural gas businesses. These factors include the traditional operating companies' ability to maintain a constructive regulatory environment,environments, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding the electric transmission and restoration following major storms. Construction continues on Plant Vogtle Units 3distribution systems, and 4 (45.7% ownership interest by Georgia Power inupdating and expanding the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. On December 3, 2015, the Mississippi PSC issued an order, based on a stipulation between Mississippi Power and the MPUS, authorizing Mississippi Power to implement rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service which is currently expected in the third quarter 2016. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. In addition, on December 31, 2015, Georgia Power and the other parties to the commercial litigation related to the construction of Plant Vogtle Units 3 and 4 entered into a settlement agreement resulting in the dismissal of the litigation. See Note 3 to the financial statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" for more information.natural gas distribution systems.
Each of theThe traditional electric operating companies hasand natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 3 to the financial statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle""Regulatory Matters" for additional information.
Another major factor affecting the Southern Company system's businesses is the profitability of the competitive market-based wholesale generating business. Southern Power's strategy is to acquire, construct,create value through various transactions including acquisitions and sell power plants, including renewable energy projects,sales of assets, development and to enterconstruction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and electric cooperatives.other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities. Southern Power is also currently pursuing the sale of a portion of equity interests in its solar assets. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and telecommunications.gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, and dispositions, accordingly.
Proposed Merger with AGL Resources
On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the Merger, each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and any shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes (Merger Consideration). Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement.
Southern Company intends to initially fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue approximately $8.0 billion in debt prior to closing the Merger and approximately $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, Southern Power growth opportunities, and other Southern Company system capital projects. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.
The Merger was approved by AGL Resources' shareholders on November 19, 2015, and the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired on December 4, 2015. Consummation of the Merger remains subject
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
to the satisfactionstrategic ventures or waiver of certain closing conditions, including, among others, (i) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC, and New Jersey Board of Public Utilities, and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company completed the required state regulatory applications in the fourth quarter 2015 and the required FCC filings in February 2016. On February 24, 2016, a stipulation and settlement agreement between Southern Company, AGL Resources, the Maryland PSC Staff, and the Maryland Office of People's Counsel was filed with the Maryland PSC. The proposed settlement remains subject to the approval of the Maryland PSC. Additionally, Southern Company received the approval of the Virginia State Corporation Commission in February 2016.
Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company’s expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016.
Prior to the Merger, Southern Company and AGL Resources will continue to operate as separate companies. Accordingly, except for specific references to the pending Merger, the descriptions of strategy and outlook and the risks and challenges Southern Company faces, and the discussion and analysis of results of operations and financial condition set forth herein relate solely to Southern Company. See Note 12 to the financial statements under "Southern Company – Proposed Merger with AGL Resources" and RISK FACTORS in Item 1A for additional information regarding the Merger and the various risks related thereto.
During 2015, the Company incurred external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $41 million.
The ultimate outcome of these matters cannot be determined at this time.
Key Performance Indicatorsinvestments accordingly.
In striving to achieve superiorattractive risk-adjusted returns while providing cost-effective energy to more than fournine million electric and gas utility customers, the Southern Company system continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share (EPS). Southern Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations duringSee RESULTS OF OPERATIONS herein for information on the months when generation needs are greatest. Company's financial performance.
Kemper County Energy Facility Status
The rate is calculated by dividing the number of hours of forced outages by total generation hours. The Southern Company system's fossil/hydro 2015 Peak Season EFORKemper County energy facility was better than the target. Transmission and distribution system reliability performance is measuredapproved by the frequency and durationMississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of outages. Performance targets for reliability are set internally based on historical performance. The Southern Company system's performance for 2015 was below the target for these transmission and distribution reliability measures primarily due$2.88 billion, net of $245 million of grants awarded to the level of storm activity inproject by the service territory duringDOE under the year. Primarily as a result of charges for estimated probable losses related to constructionClean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the Kemper IGCC, Southern Company's EPS for 2015 did not meetlignite mine and equipment, the target on a GAAP basis. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.cost of
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Excluding the COt2he charges for estimated probable losses related to construction pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC AGL Resources acquisitionplant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket).
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants). In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.
On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to an insurance settlement, Southern Company's 2015 results compared with its targetsthe Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for some2018 of these key indicators are reflected in the following chart:
|
| | | |
Key Performance Indicator | 2015
Target
Performance
| | 2015
Actual
Performance
|
System Customer Satisfaction | Top quartile in customer surveys | | Top quartile |
Peak Season System EFOR — fossil/hydro | 6.02% or less | | 1.40% |
Basic EPS — As Reported | $2.76-$2.88 | | $2.60 |
Estimated Loss on Kemper IGCC(a)
| | | $0.25 |
AGL Resources Acquisition Costs(b)
| | | $0.03 |
Additional MC Asset Recovery Settlement Costs(c)
| | | $0.01 |
EPS, excluding items* | | | $2.89 |
* The following three items are excluded from the EPS calculation:
| |
(a) | The estimated probable losses of $226 million after-tax, or $0.25 per share, related to Mississippi Power's construction of the Kemper IGCC. The estimated probable losses related to the construction of the Kemper IGCC significantly impacted the presentation of EPS in the table above, and any similar charges are items that may occur with uncertain frequency in the future. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. |
| |
(b) | The $31 million after-tax, or $0.03 per share, related to costs of the proposed Merger. Further costs related to the proposed Merger are expected to continue to occur in connection with closing the proposed Merger and supporting the related integration. See "Proposed Merger with AGL Resources" herein and Note 12 to the financial statements under "Southern Company – Proposed Merger with AGL Resources" for additional information. |
| |
(c) | Additional insurance settlement costs of $4 million after-tax, or $0.01 per share, related to the March 2009 litigation settlement with MC Asset Recovery, LLC. Further costs related to the litigation settlement are not expected. |
EPS,8.6%, excluding items does not reflect EPS asany performance adjustment, (ii) a ROE for 2019 calculated in accordance with GAAP. Mississippi Power's Performance Evaluation Plan (PEP), excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2017.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company management usesand Subsidiary Companies 2017 Annual Report
3 and 4 continued under the non-GAAP measureVogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of EPS, excluding these items, to evaluate the performance of Southern Company's ongoing business activities and its 2015 performance on a basis consistentU.S. Bankruptcy Code.
In connection with the assumptions usedEPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in developingservice by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the 2015 performance targetsimpact of payments received under a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement) and certain refunds to compare certain resultscustomers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
See Note 3 to prior periods.the financial statements under "Nuclear Construction" for additional information.
Earnings
Consolidated net income attributable to Southern Company believes this presentation is usefulwas $842 million in 2017, a decrease of $1.6 billion, or 65.6%, from the prior year. The decrease was primarily due to investorspre-tax charges of $3.4 billion ($2.4 billion after tax) related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases of $240 million in net income from Southern Company Gas (excluding the impact of $111 million in additional expense related to the Tax Reform Legislation) reflecting the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, $264 million related to net tax benefits from the Tax Reform Legislation, higher retail electric revenues resulting from increases in base rates partially offset by providing additional information for purposes of evaluating the performance ofmilder weather and lower customer usage, and increases in renewable energy sales at Southern Company's business activities. This presentation is not meant to be considered a substitute for financial measures prepared in accordance with GAAP.
See RESULTS OF OPERATIONS herein for additional information on the Company's financial performance.
EarningsPower. These increases were partially offset by higher interest and depreciation and amortization.
Consolidated net income attributable to Southern Company was $2.4 billion in 2015,2016, an increase of $404$81 million, or 20.6%3.4%, from the prior year. TheConsolidated net income increased by $114 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016. Also contributing to the increase waswere higher retail electric revenues resulting from non-fuel retail rate increases and warmer weather, primarily related to lower pre-tax chargesin the third quarter 2016, as well as the 2015 correction of $365 million ($226 million after tax) recorded in 2015 compared to pre-tax charges of $868 million ($536 million after tax) recorded in 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC and an increase in retail base rates. The increases werea Georgia Power billing error, partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. Additionally, the increase was due to increases in non-fuel operationsincome tax benefits and maintenance expenses and depreciation and amortization.
Consolidated net income attributable torenewable energy sales at Southern Company was $2.0 billion in 2014, an increase of $319 million, or 19.4%, from the prior year. The increase was primarily related to an increase in retail base rates, as well as colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013. The increase in net income was also the result of lower pre-tax charges of $868 million ($536 million after tax) recorded in 2014 compared to pre-tax charges of $1.2 billion ($729 million after tax) recorded in 2013 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC.Power. These increases were partially offset by increases inhigher interest expense, non-fuel operations and maintenance expenses.expenses, depreciation and amortization, lower wholesale capacity revenues, and higher estimated losses associated with the Kemper IGCC.
See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Basic EPS was $0.84 in 2017, $2.57 in 2016, and $2.60 in 2015, $2.19 in 2014, and $1.88 in 2013.2015. Diluted EPS, which factors in additional shares related to stock-based compensation, was $0.84 in 2017, $2.55 in 2016, and $2.59 in 2015, $2.18 in 2014, and $1.87 in 2013.2015. EPS for 20152017 was negatively impacted by $0.04 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities""Financing Activities" herein for additional information.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.1525$2.30 in 2015, $2.08252017, $2.22 in 2014,2016, and $2.0125$2.15 in 2013.2015. In January 2016,2018, Southern Company declared a quarterly dividend of 54.2558 cents per share. This is the 273rd281st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2015,2017, the actual dividend payout ratio was 83%, while273% compared to 86% for 2016. The increase was due to a significant reduction in earnings resulting from charges related to the payout ratio of net income excluding estimated probableKemper IGCC. See "Earnings" and RESULTS OF OPERATIONS – "Electricity Business – Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
losses relating to Mississippi Power's construction of the Kemper IGCC, AGL Resources acquisition costs, and additional costs related to an insurance settlement was 75%.
RESULTS OF OPERATIONS
Discussion of the results of operations is divided into twothree parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.
| | | Amount | Amount |
| 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Electricity business | $ | 2,401 |
| | $ | 1,969 |
| | $ | 1,652 |
| $ | 878 |
| | $ | 2,571 |
| | $ | 2,401 |
|
Gas business | | 243 |
| | 114 |
| | — |
|
Other business activities | (34 | ) | | (6 | ) | | (8 | ) | (279 | ) | | (237 | ) | | (34 | ) |
Net Income | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
| $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Electricity Business
Southern Company's electric utilities generate and sell electricity to retail and wholesale customers primarily in the Southeast.customers.
A condensed statement of income for the electricity business follows:
| | | Amount |
| | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Electric operating revenues | $ | 17,442 |
| | $ | (964 | ) | | $ | 1,371 |
| $ | 18,540 |
| | $ | 599 |
| | $ | 499 |
|
Fuel | 4,750 |
| | (1,255 | ) | | 495 |
| 4,400 |
| | 39 |
| | (389 | ) |
Purchased power | 645 |
| | (27 | ) | | 211 |
| 863 |
|
| 113 |
| | 105 |
|
Cost of other sales | | 69 |
| | 11 |
| | 58 |
|
Other operations and maintenance | 4,292 |
| | 33 |
| | 481 |
| 4,340 |
| | (183 | ) | | 231 |
|
Depreciation and amortization | 2,020 |
| | 91 |
| | 43 |
| 2,457 |
| | 224 |
| | 213 |
|
Taxes other than income taxes | 995 |
| | 16 |
| | 47 |
| 1,063 |
| | 24 |
| | 44 |
|
Estimated loss on Kemper IGCC | 365 |
| | (503 | ) | | (312 | ) | 3,362 |
| | 2,934 |
| | 63 |
|
Total electric operating expenses | 13,067 |
| | (1,645 | ) | | 965 |
| 16,554 |
| | 3,162 |
| | 325 |
|
Operating income | 4,375 |
| | 681 |
| | 406 |
| 1,986 |
| | (2,563 | ) | | 174 |
|
Allowance for equity funds used during construction | 226 |
| | (19 | ) | | 55 |
| 152 |
| | (48 | ) | | (26 | ) |
Interest income | 22 |
| | 4 |
| | — |
| |
Interest expense, net of amounts capitalized | 774 |
| | (20 | ) | | 6 |
| 1,011 |
| | 80 |
| | 157 |
|
Other income (expense), net | (54 | ) | | 19 |
| | (18 | ) | (83 | ) | | (8 | ) | | (43 | ) |
Income taxes | 1,326 |
| | 273 |
| | 118 |
| 82 |
| | (1,009 | ) | | (235 | ) |
Net income | 2,469 |
| | 432 |
| | 319 |
| 962 |
| | (1,690 | ) | | 183 |
|
Less: | | | | | | | | | | |
Dividends on preferred and preference stock of subsidiaries | 54 |
| | (14 | ) | | 2 |
| 38 |
| | (7 | ) | | (9 | ) |
Net income attributable to noncontrolling interests | 14 |
| | 14 |
| | — |
| 46 |
| | 10 |
| | 22 |
|
Net Income Attributable to Southern Company | $ | 2,401 |
| | $ | 432 |
| | $ | 317 |
| $ | 878 |
| | $ | (1,693 | ) | | $ | 170 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Electric Operating Revenues
Electric operating revenues for 20152017 were $17.4$18.5 billion, reflecting a $964$599 million decreaseincrease from 2014.2016. Details of electric operating revenues were as follows:
| | | Amount | Amount |
| 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Retail — prior year | $ | 15,550 |
| | $ | 14,541 |
| |
Retail electric — prior year | | $ | 15,234 |
| | $ | 14,987 |
|
Estimated change resulting from — | | | | | | |
Rates and pricing | 375 |
| | 300 |
| 508 |
| | 427 |
|
Sales growth | 50 |
| | 35 |
| |
Sales decline | | (71 | ) | | (35 | ) |
Weather | (59 | ) | | 236 |
| (281 | ) | | 153 |
|
Fuel and other cost recovery | (929 | ) | | 438 |
| (60 | ) | | (298 | ) |
Retail — current year | 14,987 |
| | 15,550 |
| |
Wholesale revenues | 1,798 |
| | 2,184 |
| |
Other electric operating revenues | 657 |
| | 672 |
| |
Retail electric — current year | | 15,330 |
| | 15,234 |
|
Wholesale electric revenues | | 2,426 |
| | 1,926 |
|
Other electric revenues | | 681 |
| | 698 |
|
Other revenues | | 103 |
| | 83 |
|
Electric operating revenues | $ | 17,442 |
| | $ | 18,406 |
| $ | 18,540 |
| | $ | 17,941 |
|
Percent change | (5.2 | )% | | 8.0 | % | 3.3 | % | | 2.9 | % |
Retail electric revenues decreased $563increased $96 million, or 3.6%0.6%, in 20152017 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 20152017 was primarily due to increased revenuesa Rate RSE increase at Alabama Power associated with an increaseeffective in rates under Rate RSE, and at Georgia Power, related to base tariff increases approved byJanuary 2017, the Georgia PSC in accordance with the 2013 ARP, and increases in collections for financing costs related to the constructionrecovery of Plant Vogtle Units 3 and 4 throughconstruction financing costs under the NCCR tariff allat Georgia Power, and an increase in retail base rates effective January 1, 2015,July 2017 at Gulf Power. See Note 3 to the financial statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.
Retail electric revenues increased $247 million, or 1.6%, in 2016 as well as higher contributions from variable demand-driven pricing from commercial and industrial customers.compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was alsoprimarily due to increases in base tariffs at Georgia Power under the implementation of2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the Kemper IGCC that began in August 2015 at Mississippi Power. The increase was partially offset by the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power.
Retail revenues increased $1.0 billion, or 6.9%,Power and the implementation of rates at Mississippi Power for certain Kemper County energy facility in-service assets, effective September 2015. These increases were partially offset by accruals in 2014 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2014 was primarily due to increased revenues at Georgia Power related to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in accordance with the 2013 ARP, and increases in collections2016 for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, as well as higher contributions from variable demand-driven pricing from commercial and industrial customers. Also contributing to the increase were increased revenuesexpected refunds at Alabama Power associated with and Georgia Power. See Note 3 to the financial statements under "Kemper County Energy Facility – Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets and increased revenues at Gulf Power primarily resulting from a retail base rate increase and an increase in the environmental cost recovery clause rate, both effective January 2014, as approved by the Florida PSC.Recovery" for additional information.
See Note 3 to the financial statements under "Retail "Regulatory Matters – Alabama Power – Rate RSE," "–Rate CNP," "– GeorgiaAlabama Power– Rate Plans," "– Gulf Power – Retail Base Rate Case," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs"RSE" and " – Rate CNP Compliance" and "Nuclear Construction" and Note 1 to the financial statements under "General" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline)decline and weather.
Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased powerPPA costs, and do not affect net income. The traditional electric operating companies may alsoeach have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.PPA capacity costs.
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues reflectgenerally represent the greatest contribution to net income and are designed to provide recovery of fixed costs andplus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
result, the Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
Wholesale electric revenues from power sales were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Capacity and other | $ | 875 |
| | $ | 974 |
| | $ | 971 |
| $ | 838 |
| | $ | 771 |
| | $ | 875 |
|
Energy | 923 |
| | 1,210 |
| | 884 |
| 1,588 |
| | 1,155 |
| | 923 |
|
Total | $ | 1,798 |
| | $ | 2,184 |
| | $ | 1,855 |
| $ | 2,426 |
| | $ | 1,926 |
| | $ | 1,798 |
|
In 2015,2017, wholesale revenues decreased $386increased $500 million, or 17.7%26.0%, as compared to the prior year due to a $287$433 million decreaseincrease in energy revenues and a $99$67 million decreaseincrease in capacity revenues.revenues, primarily at Southern Power. The decreasesincrease in energy revenues werewas primarily related to lower fuel costs and lower customer demand due to milder weather as compared to the prior year, partially offset by increases in renewable energy revenuessales arising from new solar and wind PPAs at Southern Power.facilities and non-PPA revenues from short-term sales. The decreasesincrease in capacity revenues werewas primarily due to the expiration of wholesale contracts in December 2014 at Georgia Power, unit retirements at Georgia Power,a PPA related to new natural gas facilities and PPA expirations at Southern Power. See FUTURE EARNINGS POTENTIAL – "Other Matters" for information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings.additional customer capacity requirements.
In 2014,2016, wholesale revenues increased $329$128 million, or 17.7%7.1%, as compared to the prior year due to a $326$232 million increase in energy revenues, andpartially offset by a $3$104 million increasedecrease in capacity revenues. The increase in energy revenues was primarily relateddue to increased revenue under existing contracts as well as new solar PPAsincreases in short-term sales and requirements contracts primarilyrenewable energy sales at Southern Power, increased demand resulting from colder weather in the first quarter 2014 as compared to the corresponding period in 2013, and an increase in the average cost of natural gas.partially offset by lower fuel prices. The increasedecrease in capacity revenues was primarily due to the expiration of wholesale base rate increasescontracts at MississippiGeorgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by a decrease in capacity revenues primarilyan increase due to lower customer demand anda new wholesale contract at Alabama Power in the expiration of certain requirements contracts at Southern Power.first quarter 2016.
Other Electric RevenuesPurchased Power
Other electric revenues decreased $15 million, or 2.2%, |
| | | | |
Facility/Source | Counterparty | MWs |
| Contract Term |
NCEMC | NCEMC | 100 |
| through Dec. 2021 |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" and increased $33 million, or 5.2%,"Acquisitions" of Southern Power in 2015Item 7 herein and 2014, respectively, as comparedNote 11 to the financial statements of Southern Power in Item 8 herein for additional information.
For the year ended December 31, 2017, approximately 11.3% of Southern Power's revenues were derived from Georgia Power. Southern Power actively pursues replacement PPAs prior years.to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.
Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas marketing services, wholesale gas services, and gas midstream operations.
Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains 82,000 miles of natural gas pipelines and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.6 million customers across seven states and has rates of return that are regulated by each individual state in return for exclusive franchises.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings Inc., entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The 2015 decrease was primarily due to a $16 million decrease in transmission revenues at Georgia Power primarilygoodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey Board of Public Utilities, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey Board of Public Utilities and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.
Gas marketing services is comprised of SouthStar Energy Services, LLC (SouthStar) and Nicor Energy Services Company (doing business as Pivotal Home Solutions) and provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice. SouthStar, serving approximately 774,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management. Pivotal Home Solutions, serving approximately 1.2 million service contracts, provides a suite of home protection products and services that offers homeowners predictability regarding their energy service delivery, systems, and appliances.
Wholesale gas services consists of Sequent Energy Management, L.P. and engages in natural gas storage and gas pipeline arbitrage and provides natural gas asset management and related logistical services to most of the natural gas distribution utilities as well as non-affiliate companies.
Gas midstream operations includes joint ventures in pipeline investments (including a 50% ownership interest in Southern Natural Gas Company, L.L.C. and two significant pipeline construction projects) as well as a 50% joint ownership in a significant pipeline project and wholly-owned natural gas storage facilities that enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Southern Natural Gas Company, L.L.C. is the owner of a contract7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.
For additional information on Southern Company Gas' business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Other Businesses
PowerSecure, which was acquired by Southern Company in May 2016, provides products and services in the areas of distributed energy infrastructure, energy efficiency, and utility infrastructure.
Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and also for other electric and natural gas products and services.
Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public. Southern Linc delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. Southern Linc also provides fiber optics services within the Southeast through its subsidiary, Southern Telecom, Inc.
These efforts to invest in and develop new business opportunities may offer potential returns exceeding those of rate-regulated operations. However, these activities often involve a higher degree of risk.
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2018 through 2022, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company, each traditional electric operating company, Southern Power, and Southern Company Gas in Item 7 herein. The Southern Company system's construction program consists of capital investment and capital expenditures to comply with environmental laws and regulations. The traditional electric operating companies also anticipate expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Southern Company system's asset retirement obligation liabilities. In 2018, the construction program is expected to be apportioned approximately as follows:
|
| | | | | | | | | | | | | | | |
| Southern Company system(a)(b) | Alabama Power | Georgia Power(a) | Gulf Power | Mississippi Power |
| (in billions) |
New generation | $ | 1.3 |
| $ | — |
| $ | 1.3 |
| $ | — |
| $ | — |
|
Environmental compliance(c) | 1.1 |
| 0.6 |
| 0.5 |
| 0.1 |
| — |
|
Generation maintenance | 0.9 |
| 0.5 |
| 0.2 |
| 0.1 |
| 0.1 |
|
Transmission | 0.9 |
| 0.3 |
| 0.5 |
| — |
| — |
|
Distribution | 1.2 |
| 0.5 |
| 0.5 |
| 0.1 |
| 0.1 |
|
Nuclear fuel | 0.3 |
| 0.1 |
| 0.2 |
| — |
| — |
|
General plant | 0.5 |
| 0.2 |
| 0.2 |
| — |
| — |
|
| 6.0 |
| 2.2 |
| 3.3 |
| 0.3 |
| 0.2 |
|
Southern Power(d) | 1.3 |
| | | | |
Southern Company Gas(e) | 1.7 |
| | | | |
Other subsidiaries | 0.4 |
| | | | |
Total(a) | $ | 9.4 |
| $ | 2.2 |
| $ | 3.3 |
| $ | 0.3 |
| $ | 0.2 |
|
| |
(a) | Totals may not add due to rounding. |
| |
(b) | Includes the traditional electric operating companies, Southern Power, and Southern Company Gas, as well as the other subsidiaries. See "Other Businesses" herein for additional information. |
| |
(c) | Reflects cost estimates for environmental regulations. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil-fuel-fired electric generating units or costs associated with closure and groundwater monitoring under the CCR Rule. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information. |
| |
(d) | Includes approximately $0.9 billion for planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. |
| |
(e) | Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 herein for additional information. See |
"The Southern Company System – Southern Company Gas" herein for additional information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. Projected capital expenditures of $0.1 billion related to these two natural gas distribution utilities are excluded from the amounts above.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that expired in December 2014 and a $13 million decrease in co-generation steam revenues at Alabama Power, partially offset by an $11 million increase in outdoor lighting revenues at Georgia Power. The 2014 increase was primarilycosts related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to increasesmarket opportunities and Southern Power's ability to execute its growth strategy.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been previously constructed, which may result in open access transmission tariff revenuesrevised estimates during construction. See Note 3 to the financial statements of Southern Company and transmission service revenuesGeorgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4.
Also see "Regulation – Environmental Laws and Regulations" herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Facilities" in Item 2 herein for additional information concerning Alabama Power's, Georgia Power's, and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities and Southern Company Gas' joint ownership of a pipeline facility.
Financing Programs
See each of the registrant's MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.
Fuel Supply
Electric
The traditional electric operating companies' and SEGCO's supply of electricity is primarily at fueled by natural gas and coal. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Electricity Business – Fuel and Purchased Power Expenses" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Fuel and Purchased Power Expenses" of each traditional electric operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2015 through 2017.
The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2018 coal burn requirements. These agreements have terms ranging between one and four years. In 2017, the weighted average sulfur content of all coal burned by the traditional electric operating companies was 1.12%. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional electric operating companies to remain within limits set by Phase I of the Cross-State Air Pollution Rule (CSAPR) under the Clean Air Act. In 2017, the Southern Company system did not purchase any sulfur dioxide allowances, annual nitrogen oxide emission allowances, or seasonal nitrogen oxide emission allowances from the market. As any additional environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure that the traditional electric operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each traditional electric operating company, and Southern Power in Item 7 herein for additional information on environmental matters.
SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2018, SCS has contracted for 510 Bcf of natural gas supply under agreements with remaining terms up to 15 years. In addition to natural gas supply, SCS has contracts in place
for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.
Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. The uranium, conversion services, and fuel fabrication contracts are for terms of less than 10 years with varying expiration dates. The term lengths for the enrichment services contracts are for less than 15 years with varying expiration dates. Management believes suppliers have sufficient nuclear fuel production capability to permit the normal operation of the Southern Company system's nuclear generating units.
Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's natural gas and biomass PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.
Natural Gas
Recent advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and relatively low prices for natural gas. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the state regulatory agencies in which Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and from its wholly-owned subsidiary, Sequent Energy Management, L.P., under asset management agreements in states where such agreements are approved by the applicable state regulatory agency. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.
Territory Served by the Southern Company System
Traditional Electric Operating Companies and Southern Power
The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2017, the territory had an area of approximately 120,000 square miles and an estimated population of approximately 17 million. Southern Power sells electricity at market-based rates in the wholesale market, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.
Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 14 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to the Alabama Municipal Electric Authority, and two rural distributing cooperative associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances and products and markets and sells outdoor lighting services.
Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility.
Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of each traditional electric operating company in Item 7 herein. For information relating to the number of retail customers served by customer classification for the traditional electric operating companies, see SELECTED FINANCIAL DATA of each traditional electric operating company in Item 6 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, reference is made to Item 7 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. As of December 31, 2017, there were approximately 62 electric cooperative distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. As of December 31, 2017, PowerSouth owned generating units with approximately 2,100 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. PowerSouth's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for details of Alabama Power's joint-ownership with PowerSouth of a portion of Plant Miller. Alabama Power has a system supply agreement with PowerSouth to provide 200 MWs of capacity service through December 31, 2030 with an option to extend and renegotiate in the event Alabama Power builds new generation or contracts for new capacity.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territories of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.
OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets and power purchased from other suppliers.
Four electric cooperative associations, financed by the RUS, operate within Gulf Power's service territory. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power's service territory and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided.
As of December 31, 2017, there were approximately 72 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
As of December 31, 2017, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Southern Power assumed or entered into PPAs with some of the traditional electric operating companies, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" above and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 herein for additional information concerning Southern Power's PPAs.
SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.
Southern Company Gas
Southern Company Gas is engaged in the distribution of natural gas in seven states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2017 are as follows:
|
| | | | | |
Utility | State | Number of customers |
| Approximate miles of pipe |
|
| | (in thousands) | |
Nicor Gas | Illinois | 2,228 |
| 34,300 |
|
Atlanta Gas Light Company | Georgia | 1,622 |
| 33,500 |
|
Virginia Natural Gas | Virginia | 299 |
| 5,600 |
|
Elizabethtown Gas(*) | New Jersey | 292 |
| 3,200 |
|
Florida City Gas | Florida | 109 |
| 3,700 |
|
Chattanooga Gas Company | Tennessee | 66 |
| 1,600 |
|
Elkton Gas(*) | Maryland | 7 |
| 100 |
|
Total | | 4,623 |
| 82,000 |
|
| |
(*) | For information relating to the pending asset sales of Elizabethtown Gas and Elkton Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Merger, Acquisition, and Disposition Activities" of Southern Company Gas in Item 7 herein and Note 11 to the financial statements of Southern Company Gas under "Proposed Sale of Elizabethtown Gas and Elkton Gas" in Item 8 herein. |
For information relating to the sources of revenue for Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Competition
Electric
The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992, which allowed IPPs to access a utility's transmission network in order to sell electricity to other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may extend or maintain its electric
system subject to certain regulatory approvals; extensions of facilities by such utility, or extensions of facilities into that area by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate that are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors.
Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales across various U.S. utility markets. The needs of these markets are driven by the demands of end users and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.
As of December 31, 2017, Alabama Power had cogeneration contracts in effect with eight industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2017, Alabama Power purchased approximately 98 million KWHs from such companies at a cost of $3 million.
As of December 31, 2017, Georgia Power had contracts in effect with 27 small power producers whereby Georgia Power purchases their excess generation. During 2017, Georgia Power purchased 1.6 billion KWHs from such companies at a cost of $114 million. Georgia Power also has PPAs for electricity with four cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2017, Georgia Power purchased 26 million KWHs at a cost of $0.7 million from these facilities.
Also during 2017, Georgia Power purchased energy from three customer-owned generating facilities. These customers provide only energy to Georgia Power, make no capacity commitment, and are not dispatched by Georgia Power. During 2017, Georgia Power purchased a total of 317 million KWHs from the three customers at a cost of approximately $25 million.
As of December 31, 2017, Gulf Power had agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases "as available" energy from customer-owned generation. During 2017, Gulf Power purchased 277 million KWHs from such companies for approximately $7 million.
As of December 31, 2017, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2017, Mississippi Power did not purchase any excess generation from this customer.
Natural Gas
Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.
Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.
Customer demand for natural gas could be affected by numerous factors, including:
changes in the availability or price of natural gas and other forms of energy;
general economic conditions;
energy conservation, including state-supported energy efficiency programs;
legislation and regulations;
the cost and capability to convert from natural gas to alternative energy products; and
technological changes resulting in displacement or replacement of natural gas appliances.
The natural gas-related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.
The availability and affordability of natural gas have provided cost advantages and further opportunity for growth of the businesses.
Seasonality
The demand for electric power and natural gas supply is affected by seasonal differences in the weather. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less power and natural gas when weather conditions are milder.
Regulation
State Commissions
The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Southern Company System" and "Rate Matters" herein for additional information.
Federal Power Act
The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2017, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,670,000 KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1,087,296 KWs.
In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission also filed petitions for rehearing of the FERC order. In April 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. The order also denied all of the other rehearing requests. In May 2016, Alabama Rivers Alliance and American Rivers filed a second rehearing request and, in June 2016, also filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit for review of the license and the rehearing denial order. The FERC issued an order in September 2016 denying the second rehearing request, and American Rivers and Alabama Rivers Alliance subsequently filed an appeal of that order at the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit consolidated the two appeals into one proceeding.
In 2017, Alabama Power continued the process of developing an application to relicense the Harris Dam project on the Tallapoosa River, which is expected to be filed with the FERC by November 30, 2021. The current Harris Dam project license will expire on November 30, 2023.
In 2017, Georgia Power continued the process of developing an application to relicense the Wallace Dam project on the Oconee River. The current Wallace Dam project license will expire on June 1, 2020. Georgia Power's hydro electric licenses expiring in 2023 include the Lloyd Shoals project, the Riverview project, and the Langdale project. The FERC relicensing proceedings for these three projects are expected to begin in 2018.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 KW capacity. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Licenses for all projects, excluding those discussed above, expire in the years 2023-2066 in the case of Alabama Power's projects and in the years 2035-2044 in the case of Georgia Power's projects.
Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another,
the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.
The ultimate outcome of these matters cannot be determined at this time.
Nuclear Regulation
Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1 and 2 expire in 2047 and 2049, respectively.
In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for additional information.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
Environmental Laws and Regulations
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. For Southern Company Gas, substantially all of these costs are related to former manufactured gas plants sites, which are primarily recovered through existing ratemaking provisions. See Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 herein for additional information.
Compliance with federal environmental laws and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional electric operating company, Southern Power, SEGCO, and Southern Company Gas. New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein for additional information about environmental issues, including, but not limited to, proposed and final regulations related to air quality, water quality, CCRs, and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 herein for additional information about environmental issues and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 herein for additional information about environmental remediation liabilities.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state-level adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates
could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See "Construction Program" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each of the traditional electric operating companies, Southern Power, and Southern Company Gas in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
Rate Matters
Rate Structure and Cost Recovery Plans
Electric
The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.
The traditional electric operating companies recover certain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved compliance, storm damage, and certain other costs are recovered at Alabama Power, Gulf Power, and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power and Gulf Power through periodic base rate proceedings.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company and each of the traditional electric operating companies under "Retail Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also, see Note 1 to the financial statements of Southern Company and each of the traditional electric operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and compliance costs through rate mechanisms.
See "Integrated Resource Planning" herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover financing costs for construction of Plant Vogtle Units 3 and 4 during the construction period beginning in 2011.
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Rate Recovery" of Mississippi Power in Item 7 herein for information on cost recovery plans with respect to the Kemper County energy facility.
The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of each of the registrants in Item 7 herein for information on the traditional electric operating companies' and Southern Power Company's market-based rate authority and pending FERC proceedings relating to this authority.
Mississippi Power serves long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of Mississippi Power's operating revenues in 2017 and are largely subject to rolling 10-
year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Natural Gas
Southern Company Gas' seven natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies with respect to rates charged to their customers, maintenance of accounting records, and various service and safety matters. Rates charged to these customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide each natural gas distribution utility the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt, and provide a reasonable return. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
With the exception of Atlanta Gas Light Company, which operates in a deregulated environment in which gas marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas.
The natural gas distribution utilities, excluding Atlanta Gas Light Company, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing natural gas for their customers. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Utility Regulation and Rate Design" of Southern Company Gas in Item 7 herein and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.
Integrated Resource Planning
Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See "Environmental Laws and Regulations" above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies.
Certain of the traditional electric operating companies are required to file IRPs with their respective state PSC as discussed below.
Georgia Power
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Rate Plans" and " – Integrated Resource Plan" and "Nuclear Construction" and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans," "– Integrated Resource Plan," and "– Nuclear Construction" in Item 8 herein for additional information.
Gulf Power
Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power's estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state's electric utilities are reviewed by the Florida PSC and subsequently classified as either "suitable" or "unsuitable." The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical power plant site certification proceedings. Under
Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC.
Gulf Power's most recent 10-year site plan was classified by the Florida PSC as "suitable" in November 2017. The plan identifies environmental regulations and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality," "– Environmental Laws and Regulations – Coal Combustion Residuals," and "– Global Climate Issues" of Gulf Power in Item 7 herein.
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) in March 2016. In August 2016, the Florida PSC approved Gulf Power's request to reclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date, totaling approximately $63 million, to a regulatory asset. Gulf Power began amortizing the investment balances over 15 years effective January 1, 2018 as determined in a rate case settlement agreement approved by the Florida PSC on April 4, 2017.
Mississippi Power
Mississippi Power's 2010 IRP indicated that, among other things, Mississippi Power planned to construct the Kemper County energy facility as an IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality" and "– Global Climate Issues" of Mississippi Power in Item 7 herein.
On February 6, 2018, the Mississippi PSC approved a settlement agreement related to cost recovery for the Kemper County energy facility, pursuant to which Mississippi Power agreed to file a Reserve Margin Plan (RMP) by August 2018. The RMP will include many of the same aspects of a traditional IRP, but the RMP will also contain alternatives proposed by Mississippi Power to address its current capacity which is in excess of Mississippi Power's long-term targeted reserve margin. The ultimate outcome of this matter cannot be determined at this time.
For additional information regarding the Kemper County energy facility, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein.
Employee Relations
The Southern Company system had a total of 31,344 employees on its payroll at December 31, 2017.
|
| | |
| Employees at December 31, 2017 |
Alabama Power | 6,613 |
|
Georgia Power | 6,986 |
|
Gulf Power | 1,288 |
|
Mississippi Power | 1,242 |
|
PowerSecure | 1,448 |
|
SCS | 3,740 |
|
Southern Company Gas | 5,318 |
|
Southern Nuclear | 3,936 |
|
Southern Power | 541 |
|
Other | 232 |
|
Total | 31,344 |
|
The traditional electric operating companies and the natural gas distribution utilities have separate agreements with local unions of the IBEW and the Utilities Workers Union of America generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.
Alabama Power has agreements with the IBEW in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2021.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through April 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through May 1, 2019. In 2015, Mississippi Power signed a separate agreement with the IBEW related solely to the Kemper County energy facility; that current agreement is in effect through March 15, 2021. In August 2017, Mississippi Power signed an agreement with the IBEW that added several job classifications and provided guidelines related to the reorganization at the Kemper County energy facility.
Southern Nuclear has a five-year agreement with the IBEW covering certain employees at Plants Hatch and Plant Vogtle Units 1 and 2, which is in effect through June 30, 2021. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley is in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.
The natural gas distribution utilities have separate agreements with local unions of the IBEW and Utilities Workers Union of America covering wages, working conditions, and procedures for handling grievances and arbitration. Nicor Gas' agreement with the IBEW is effective through February 29, 2020. Virginia Natural Gas' agreement with the IBEW is effective through May 16, 2020. Elizabethtown Gas' agreement with the Utility Workers Union of America is effective through November 21, 2019. The agreements also make the terms of the Southern Company Gas pension plan subject to collective bargaining with the unions when significant changes to the benefit accruals are considered by Southern Company Gas.
Effective in December 2017, 538 employees transferred from SCS to Southern Power. Southern Power became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including accumulated other comprehensive income impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, Southern Power's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations.
Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, includingMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 ofeach registrant, and other documents filed by Southern Company and/or itssubsidiaries with the SEC from time to time, the following factors should becarefully considered in evaluating Southern Company and its subsidiaries. Suchfactors could affect actual results and cause results to differ materially fromthose expressed in any forward-looking statements made by, or on behalf of, SouthernCompany and/or its subsidiaries.
UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS
Southern Company and its subsidiaries are subject to substantial state and federal governmentalregulation. Compliance with current and future regulatory requirements andprocurement of necessary approvals, permits, and certificates may result insubstantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses. Jointly-owned facilities may be subject to regulation by governmental agencies of more than one state and those state's governmental agencies may have different policies with respect to such jointly-owned facilities. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs (including a reasonable return on invested capital) through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. A state PSC or other applicable state regulatory agency, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and by Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments must be approved by the FERC. These wholesale rates could be affected by changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority. The FERC rules related to retaining the authority to sell electricity at market-based rates in the wholesale markets are important for the traditional electric operating companies and Southern Power if they are to remain competitive in the wholesale markets in which they operate.
The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs or otherwise negatively affect their results of operations.
The Southern Company system's costs of compliance with environmental laws are significant. The costs of compliance with current and future environmental laws and the incurrence of environmental liabilities could negatively impact the net income, cash flows, and financial condition of the registrants.
The Southern Company system's operations are subject to extensive regulation by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and the protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. The registrants expect that these expenditures will continue to be significant in the future.
The EPA has adopted and is implementing regulations governing air and water quality, including the emission of nitrogen oxide, sulfur dioxide, fine particulate matter, ozone, mercury, and other air pollutants under the Clean Air Act and regulations governing cooling water intake structures and effluent guidelines for steam electric generating plants under the Clean Water Act. The EPA also is reconsidering regulations governing the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at power generation plants.
Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations affected by historical operations or subject to contractual obligations.
Existing environmental laws and regulations may be revised or new laws and regulations related to air, water, land, and the protection of other natural resources may be adopted or become applicable to the traditional electric operating companies, Southern Power, and/or Southern Company Gas.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, releases of regulated substances, and alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity or natural gas.
Compliance with any new or revised environmental laws or regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The ultimate impact will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may affect their demand for electricity and natural gas.
The Southern Company system may be exposed to regulatory and financial risks related to the impact of greenhouse gas (GHG) legislation and regulation.
In 2015, the EPA published final rules limiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of the litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO2 emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing GHG emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.
Costs associated with these actions could be significant to the utility industry and the Southern Company system. However, the ultimate impact of these environmental laws and regulations will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future GHG constraints may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs. Future GHG constraints focused on minimizing emissions from natural gas, albeit lower than other fossil fuels, could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.
The net income of Southern Company, the traditional electric operating companies, and Southern Power could be negatively impacted by changes in regulations related to transmission planning processes and competition in the wholesale electric markets.
The traditional electric operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority of transmission revenues are collected through retail rates. FERC rules pertaining to regional transmission planning and cost allocation present challenges to transmission planning and the wholesale market structure in the Southeast. The key impacts of these rules include:
possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;
delays and additional processes for developing transmission plans; and
possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.
The FERC rules related to transmission are intended to spur the development of new transmission infrastructure to promote and encourage the integration of renewable sources of supply as well as facilitate competition in the wholesale market by providing more choices to wholesale power customers. Technology changes in the power and fuel industries continue to create significant impacts to wholesale transaction cost structures. The impact of these and other such developments and the effect of changes in levels of wholesale supply and demand are uncertain. The financial condition, net income, and cash flows of Southern Company, the traditional electric operating companies, and Southern Power could be adversely affected by these and other changes.
The traditional electric operating companies and Southern Power could be subject to higher costs as a result of implementing and maintaining compliance with the North American Electric Reliability Corporation mandatory reliability standards along with possible associated penalties for non-compliance.
Owners and operators of bulk power systems, including the traditional electric operating companies, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation and enforced by the FERC. Compliance with or changes in the mandatory reliability standards may subject the traditional electric operating companies and Southern Power to higher operating costs and/or increased capital expenditures. If any traditional electric operating company or Southern Power is found to be in noncompliance with these standards, such traditional electric operating company or Southern Power could be subject to sanctions, including substantial monetary penalties.
Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation, which has and could have a further material impact on the results of operations, financial condition, and cash flows of the registrants.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation significantly changes the U.S. Internal Revenue Code by, among other things, reducing the federal corporate income tax rate to 21% and repealing the corporate alternative minimum tax. As a result of the tax rate reduction, Southern Company recorded net, non-cash federal income tax benefits of $264 million in the fourth quarter 2017, comprised primarily of a $743 million tax benefit resulting from reductions in deferred tax liabilities at Southern Power, partially offset by tax expenses of $372 million and $93 million resulting from reductions in deferred tax assets at Mississippi Power and Southern Company Gas, respectively.
The tax rate reduction also resulted in a $6.9 billion increase in regulatory liabilities and a $0.4 billion decrease in regulatory assets across the traditional electric operating companies and the natural gas distribution utilities. The regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies.
For businesses other than regulated utility businesses, the Tax Reform Legislation allows 100% bonus depreciation of qualified property through 2022, which phases down through 2027, and limits interest expense deductions. Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. The Tax Reform Legislation retains normalization provisions for public utility property and existing renewable energy incentives. However, the tax rate reduction delays the utilization of renewable tax credit carryforwards as described in Note 5 to the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Power under "Federal Tax Reform Legislation" in Item 8 herein.
The Tax Reform Legislation also includes provisions that limit the utilization of future net operating losses and limit the deductibility of certain executive compensation and other expenses. Further, while it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as funds from operations to debt percentage, used by the credit rating agencies to assess the registrants, Southern Company Gas Capital, and Nicor Gas may be negatively impacted.
The Tax Reform Legislation is unclear in certain respects and will require interpretations, guidance, and implementing regulations by the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation and are assessing whether any potential actions are available to mitigate adverse impacts of the legislation. Southern Company and its subsidiaries may identify additional impacts as they further assess the Tax Reform Legislation and as the IRS issues interpretations and implements regulations. Southern Company will continue to monitor the actions of state legislatures and state taxing authorities to see how the states may adopt and implement the Tax Reform Legislation. While the ultimate impact of the Tax Reform Legislation, future interpretations and implementation of regulations by the IRS and state tax authorities, and any mitigating actions Southern Company and its subsidiaries may take cannot be determined at this time, the Tax Reform Legislation had and could have a further material impact on the results of operations, financial condition and cash flows of the registrants.
OPERATIONAL RISKS
The financial performance of Southern Company and its subsidiaries may be adverselyaffected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.
The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions. There are many risks that could affect these operations and performance of corporate functions, including:
operator error or failure of equipment or processes;
accidents or explosions;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
terrorist attacks (physical and/or cyber);
fuel or material supply interruptions;
transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities;
compliance with mandatory reliability standards, including mandatory cyber security standards;
implementation of new technologies;
information technology system failure;
cyber intrusion;
an environmental event, such as a spill or release; and
catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, tornadoes, and storms, pandemic health events such as influenzas, or other similar occurrences.
A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or natural gas distribution or storage facilities or an increase in co-generation steam revenues atthe cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional electric operating company, Southern Power, or Southern Company Gas and of Southern Company.
Operation of nuclear facilities involves inherent risks, including environmental,safety, health, regulatory, natural disasters, terrorism, and financial risks, that could result in fines or theclosure of the nuclear units owned by Alabama Power or Georgia Powerand which may present potential exposures in excess of insurance coverage.
Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represent approximately 3,680 MWs, or 8% of the Southern Company system's electric generation capacity as of December 31, 2017. In addition, these units generated approximately 25% of the total KWHs generated by each of Alabama Power and Georgia Power in the year ended December 31, 2017. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction of Plant Vogtle Units 3 and 4. Due solely to the increase in nuclear generating capacity, the below risks are expected to increase incrementally once Plant Vogtle Units 3 and 4 are operational. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as:
the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;
uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;
potential liabilities arising out of the operation of these facilities;
significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;
the threat of a possible terrorist attack, including a potential cyber security attack; and
the potential impact of an accident or natural disaster.
It is possible that damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a serious nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units or require additional safety measures at new and existing units. Moreover, a major incident at any nuclear facility in the U.S., including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.
In addition, potential terrorist threats could result in increased nuclear licensing or compliance costs that are difficult to predict.
Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs.
Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these regulatory requirements could result in substantial monetary penalties or potential early retirement of storage facilities, which could trigger an associated impairment. The occurrence of any of these events not fully covered by insurance or otherwise could adversely affect Southern Company Gas' and Southern Company's financial condition and results of operations.
Physical attacks, both threatened and actual, could impact the ability of the traditional electric operating companies, Southern Power, and Southern Company Gas to operate and could adversely affect financial results and liquidity.
The traditional electric operating companies, Southern Power, and Southern Company Gas face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical attacks against key suppliers or service providers could have a similar effect on Southern Company and its subsidiaries.
Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical attacks. If assets were to fail, be physically damaged, or be breached and were not recovered in a timely way, the traditional electric operating companies, Southern Power, or Southern Company Gas, as applicable, may be unable to fulfill critical business functions. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or physical security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
These events could harm the reputation of and negatively affect the financial results of the registrants through lost revenues and costs to repair damage, if such costs cannot be recovered.
An information security incident, including a cybersecurity breach, or the failure of one or more key information technology systems, networks, or processes could impact the ability of the registrants to operate and could adversely affect financial results and liquidity.
Information security risks have generally increased in recent years as a result of the proliferation of new technology and increased sophistication and frequency of cyber attacks and data security breaches. The traditional electric operating
companies, Southern Power, and Southern Company Gas operate in highly regulated industries that require the continued operation of sophisticated information technology systems and network infrastructure, which are part of interconnected distribution systems. Because of the critical nature of the infrastructure, increased connectivity to the internet, and technology systems' inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, or other types of data security breaches, Southern Company and its subsidiaries face a heightened risk of cyberattack. Parties that wish to disrupt the U.S. bulk power system or Southern Company system operations could view these computer systems, software, or networks as targets. The registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their information technology systems and confidential data or to attempts to disrupt utility operations. As a result, Southern Company and its subsidiaries face on-going threats to their assets, including assets deemed critical infrastructure, where databases and systems have been, and will likely continue to be, subject to advanced computer viruses or other malicious codes, unauthorized access attempts, phishing, and other cyber attacks. While there has been no material impact on business or operations from these attacks, the registrants cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure.
In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third party service providers that could also be targets of cyber attacks. Generally, Southern Company and its subsidiaries enter certain contractual security guarantees and assurances with these third parties to help ensure the security and safety of this information.
Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external cyber attacks. If assets were to fail or be breached and were not recovered in a timely way, the affected registrant may be unable to fulfill critical business functions, and sensitive and other data could be compromised. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected registrant to penalties and claims from regulators or other third parties. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
These events could negatively affect the financial results of the registrants through lost revenues, costs to recover and repair damage, and costs associated with governmental actions in response to such attacks, litigation, and reputational damage if such costs cannot be recovered through insurance or otherwise.
The Southern Company system may not be able to obtainadequate natural gas and other fuel supplies required to operate the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.
The traditional electric operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, as applicable, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs and potentially reduce the net income of the affected traditional electric operating company or Southern Power and Southern Company.
Southern Company Gas' primary business is the distribution and sale of natural gas through its regulated and unregulated subsidiaries. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane or a pipeline failure. Southern Company Gas also relies on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to Southern Company Gas' distribution systems. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Disruption in natural gas supplies could limit the ability to fulfill these contractual obligations.
The traditional electric operating companies and Southern Power have become more dependent on natural gas for a portion of their electric generating capacity. In many instances, the cost of purchased power for the traditional electric operating companies and Southern Power is influenced by natural gas prices. Historically, natural gas prices have been more volatile than prices of other fuels. In recent years, domestic natural gas prices have been depressed by robust supplies, including production from shale gas. These market conditions, together with additional regulation of coal-fired generating units, have increased the traditional electric operating companies' reliance on natural gas-fired generating units.
The traditional electric operating companies are also dependent on coal for a portion of their electric generating capacity. The traditional electric operating companies depend on coal supply contracts, and the counterparties to these agreements may not fulfill their obligations to supply coal to the traditional electric operating companies. The suppliers may experience financial or
technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers may not be required to supply coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their coal requirements under these contracts, they may be required to purchase their coal requirements at higher prices, which may not be recoverable through rates.
The revenues of Southern Company, the traditional electric operating companies, and SouthernPower depend inpart on sales under PPAs. The failure of a counterparty to one of these PPAs toperform its obligations, the failure of the traditional electric operating companies or Southern Power to satisfy minimum requirements under the PPAs, or the failure to renew the PPAs or successfully remarket the related generating capacity could have a negativeimpact on the net income and cash flows of the affected traditional electric operating companyor Southern Power and of Southern Company.
Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power's top three customers, Georgia Power, Duke Energy Corporation, and Morgan Stanley Capital Group accounted for 11.3%, 6.7%, and 4.5%, respectively, of Southern Power's total revenues for the year ended December 31, 2017. In addition, the traditional electric operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. The failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.
Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. The failure of the traditional electric operating companies or Southern Power to satisfy minimum operational or availability requirements under these PPAs could result in payment of damages or termination of the PPAs.
The asset management arrangements between Southern Company Gas' wholesale gas services and its customers, including the natural gas distribution utilities, may not be renewed or may be renewed at lower levels, which could have a significant impact on Southern Company Gas' financial results.
Southern Company Gas' wholesale gas services currently manages the storage and transportation assets of the natural gas distribution utilities except Nicor Gas. The profits earned from the management of these affiliate assets are shared with the respective affiliate's customers (and for Atlanta Gas Light Company with the Georgia PSC's Universal Service Fund), except for Chattanooga Gas Company and Elkton Gas where wholesale gas services are provided under annual fixed-fee agreements. These asset management agreements are subject to regulatory approval and such agreements may not be renewed or may be renewed with less favorable terms.
Southern Company Gas' wholesale gas services also has asset management agreements with certain non-affiliated customers and its financial results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.
Increased competition could negatively impact Southern Company's and its subsidiaries' revenues, results of operations, and financial condition.
The Southern Company system faces increasing competition from other companies that supply energy or generation and storage technologies. Changes in technology may make the Southern Company system's electric generating facilities owned by the traditional electric operating companies and Southern Power less competitive. Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas also faces competition in its unregulated markets.
A key element of the business models of the traditional electric operating companies and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation and storage technologies that produce and store power, including fuel cells, microturbines, wind turbines, solar cells, and batteries. Advances in technology or changes in laws or regulations could reduce the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology.
It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional electric operating companies, or Southern Power.
Southern Company Gas' gas marketing services is affected by competition from other energy marketers providing similar services in Southern Company Gas' service territories, most notably in Illinois and Georgia. Southern Company Gas' wholesale gas services competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines based on the ability to aggregate competitively-priced commodities with transportation and storage capacity. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region.
If new technologies become cost competitive and achieve sufficient scale, the market share of the traditional electric operating companies, Southern Power, and Southern Company Gas could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets. If state PSCs or other applicable state regulatory agencies fail to adjust rates to reflect the impact of any changes in loads, increasing self-generation, and the growth of distributed generation, the financial condition, results of operations, and cash flows of Southern Company and the affected traditional electric operating company or Southern Company Gas could be materially adversely affected.
Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company's and its subsidiaries' results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with major construction projects and ongoing operations. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses. If Southern Company and its subsidiaries are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
CONSTRUCTION RISKS
The registrants may incuradditional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities ofthe traditional electric operating companies, Southern Power, and Southern Company Gas requireongoing capital expenditures, including those to meet environmental standards.
General
The businesses of the registrants require substantial capital expenditures for investments in new facilities and, for the traditional electric operating companies, capital improvements to transmission, distribution, and generation facilities, and, for Southern Company Gas, capital improvements to natural gas distribution and storage facilities, including those to meet environmental standards. Certain of the traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company Gas is replacing certain pipelines in its natural gas distribution system and is involved in two new gas pipeline construction projects. The Southern Company system intends to continue its strategy of developing and constructing other new facilities, expanding or updating existing facilities, and adding environmental control equipment. These types of projects are long term in nature and in some cases include the development and construction of facilities with designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:
shortages and inconsistent quality of equipment, materials, and labor;
changes in labor costs and productivity;
work stoppages;
contractor or supplier delay or non-performance under construction, operating, or other agreements or non-performance by other major participants in construction projects;
delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;
delays associated with start-up activities, including major equipment failure and system integration, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC or other applicable state regulatory agency);
operational readiness, including specialized operator training and required site safety programs;
impacts of new and existing laws and regulations, including environmental laws and regulations;
the outcome of legal challenges to projects, including legal challenges to regulatory approvals;
failure to construct in accordance with permitting and licensing requirements;
failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;
continued public and policymaker support for such projects;
adverse weather conditions or natural disasters;
other unforeseen engineering or design problems;
changes in project design or scope;
environmental and geological conditions;
delays or increased costs to interconnect facilities to transmission grids; and
unanticipated cost increases, including materials and labor, and increased financing costs as a result of changes in market interest rates or as a result of construction schedule delays.
If a traditional electric operating company, Southern Power, or Southern Company Gas is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Additionally, each Southern Company Gas pipeline construction project involves separate joint venture participants, Southern Power participates in partnership agreements with respect to renewable energy projects, and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction.
Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and may not be recoverable through regulated rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of the affected registrant.
Construction delays could result in the loss of otherwise available investment tax credits, PTCs, and other tax incentives. Furthermore, if construction projects are not completed according to specification, a traditional electric operating company, Southern Power, or Southern Company Gas and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide safe and reliable operations.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4.
Plant Vogtle Units 3 and 4 construction and rate recovery
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under a substantially fixed price engineering, procurement, and construction agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the EPC Contractor to allow construction to continue (Interim Assessment Agreement). The Interim Assessment Agreement expired on July 27, 2017 upon the effectiveness of a services agreement between the Vogtle Owners and the EPC Contractor for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear (Vogtle Services Agreement). In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth Vogtle Construction Monitoring (VCM) report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel Power Corporation (Bechtel) serving as the primary construction contractor. Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The construction completion agreement between Georgia Power, for itself and as agent for the other Vogtle Owners, and Bechtel (Bechtel Agreement) is a cost reimbursable plus
fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the original engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 (Contractor Settlement Agreement) was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined below) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the return on equity (ROE) used to calculate the Nuclear Construction Cost Recovery (NCCR) tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 Alternative Rate Plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for allowance for funds used during construction equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the settlement agreement approved by the Georgia PSC on December 20, 2016. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding Toshiba's guarantee of certain obligations of the EPC Contractor (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's construction work in progress balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time.
See Note 3 to the financial statements of Southern Company under "Nuclear Construction" and of Georgia Power under "Retail Regulatory Matters - Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Southern Company Gas' significant investments in pipelines and pipeline development projects involve financial and execution risks.
Southern Company Gas has made significant investments in existing pipelines and pipeline development projects. Many of the existing pipelines are, and when completed many of the pipeline development projects will be, operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of the investment. In addition, from time to time, Southern Company Gas may be required to contribute additional capital to a pipeline joint venture or guarantee the obligations of such joint venture.
With respect to certain pipeline development projects, Southern Company Gas will rely on its joint venture partners for construction management and will not exercise direct control over the process. All of the pipeline development projects are dependent on contractors for the successful and timely completion of the projects. Further, the development of pipeline projects involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require the expenditure of significant amounts of capital. These projects may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' capital expenditures to exceed its initial expectations. Moreover, Southern Company Gas' revenues will not increase immediately upon the expenditure of funds on a pipeline project. Pipeline construction occurs over an extended period of time and Southern Company Gas will not receive material increases in outdoor lightingrevenues until the project is placed in service.
The occurrence of any of the foregoing events could adversely affect the results of operations, cash flows, and solar application feefinancial condition of Southern Company Gas and Southern Company.
FINANCIAL, ECONOMIC, AND MARKET RISKS
The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to risks, many of which are beyondtheir control, including changes in energy prices and fuel costs, which may reduce revenues and increase costs.
The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Among the factors that could influence energy prices and fuel costs are:
prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;
demand for energy and the extent of additional supplies of energy available from current or new competitors;
liquidity in the general wholesale electricity and natural gas markets;
weather conditions impacting demand for electricity and natural gas;
seasonality;
transmission or transportation constraints, disruptions, or inefficiencies;
availability of competitively priced alternative energy sources;
forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;
the financial condition of market participants;
the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels, including natural gas;
natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and
federal, state, and foreign energy and environmental regulation and legislation.
Certain of these factors could increase the expenses of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company.
Historically, the traditional electric operating companies and Southern Company Gas from time to time have experienced underrecovered fuel and/or purchased gas cost balances and may experience such balances in the future. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through cost recovery clauses, recovery may be denied if costs are deemed to be imprudently incurred, and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional electric operating company or Southern Company Gas and Southern Company.
The registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the traditional electric operating companies, Southern Power, and Southern Company Gas.
The consumption and use of energy are fundamentally linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. Any economic downturn could negatively impact customer growth and usage per customer, thus reducing the sales of energy and revenues. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the traditional electric operating companies, Southern Power, and Southern Company Gas.
Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy.
Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and Southern Company Gas have PSC or other applicable state regulatory agency mandates to promote energy efficiency. Conservation programs could impact the financial results of the registrants in different ways. For example, if any traditional electric operating company or Southern Company Gas is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional electric operating company or Southern Company Gas and Southern Company. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.
In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, new electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. The Southern Company system uses best available methods and experience to incorporate the effects of changes in customer behavior, state and federal programs, PSC or other applicable state regulatory agency mandates, and technology, but the Southern Company system's planning processes may not appropriately estimate and incorporate these effects.
All of the factors discussed above could adversely affect Southern Company's, the traditional electric operating companies', Southern Power's, and/or Southern Company Gas' results of operations, financial condition, and liquidity.
The operating results of the registrants are affected by weather conditions and may fluctuate on a seasonal andquarterly basis. In addition, catastrophic events, such as fires, earthquakes, hurricanes, tornadoes, floods, droughts, and storms, could result in substantial damage to or limit the operation of the properties of the traditional electric operating companies, Southern Power, and/or Southern Company Gas and could negatively impact results of operation, financial condition, and liquidity.
Electric power and natural gas supply are generally seasonal businesses. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at Georgiathat time. In other areas, power demand peaks during the winter months. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the registrants may fluctuate substantially on a seasonal basis. In addition, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less
power and natural gas when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, and available cash of the affected registrant.
Further, volatile or significant weather events could result in substantial damage to the transmission and distribution lines of the traditional electric operating companies, the generating facilities of the traditional electric operating companies and Southern Power, and the natural gas distribution and storage facilities of Southern Company Gas. The traditional electric operating companies, Southern Power, and Southern Company Gas have significant investments in the Atlantic and Gulf Coast regions and Southern Power has wind and natural gas investments in various states which could be subject to severe weather, as well as solar investments in various states which could be subject to natural disasters. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.
In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. Historically, the traditional electric operating companies from time to time have experienced deficits in their storm cost recovery reserve balances and may experience such deficits in the future. Any denial by the applicable state PSC or other applicable state regulatory agency or delay in recovery of any portion of such costs could have a material negative impact on a traditional electric operating company's or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.
In addition, damages resulting from significant weather events within the service territory of any traditional electric operating company or Southern Company Gas or affecting Southern Power's customers may result in the loss of customers and reduced demand for energy for extended periods. Any significant loss of customers or reduction in demand for energy could have a material negative impact on a traditional electric operating company's, Southern Power's, or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.
Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
Southern Company and its subsidiaries have made significant acquisitions and investments in the past and may in the future make additional acquisitions, dispositions, or other strategic ventures or investments, including the proposed sale by Pivotal Utility Holdings, a wholly-owned subsidiary of Southern Company Gas, of the assets of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, and the potential sale by Southern Power of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers.
Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk. These transactions may also affect the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
These transactions also involve risks, including:
they may not result in an increase in franchise feesincome or provide an adequate return on capital or other anticipated benefits;
they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;
they may not be successfully integrated into the acquiring company's operations and/or internal control processes;
the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;
they may result in decreased earnings, revenues, or cash flow;
expected benefits of a transaction may be dependent on the cooperation or performance of a counterparty; or
for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through rates may not be recoverable.
Southern Company and Southern Company Gas are holding companies and are dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations, including making interest and principal payments on outstanding indebtedness and, for Southern Company, to pay dividends on its common stock.
Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' respective consolidated assets are held by subsidiaries. A significant portion of Southern Company Gas' debt is issued by its 100%-owned subsidiary, Southern Company Gas Capital, and is fully and unconditionally guaranteed by Southern Company Gas. Southern Company's and Southern Company Gas' ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is primarily dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company or Southern Company Gas, the respective subsidiaries have regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. These subsidiaries are separate legal entities and have no obligation to provide Southern Company or Southern Company Gas with funds. In addition, Southern Company and Southern Company Gas may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.
A downgrade in the credit ratings of any of the registrants, Southern Company Gas Capital, or Nicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require posting of collateral or replacing certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for the registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. The registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any registrant, Southern Company Gas Capital, or Nicor Gas, borrowing costs likely would increase, including automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used, and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.
Uncertainty in demand for energy can result in lower earnings or higher costs. If demand for energy falls short of expectations, it could result in potentially stranded assets. If demand for energy exceeds expectations, it could result in increased costs forpurchasing capacity in the open market or building additional electric generation and transmissionfacilities or natural gas distribution and storage facilities.
Southern Company, the traditional electric operating companies, and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. Southern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines and storage facilities, replacing existing pipelines, rewatering storage facilities, and entering new markets and/or expanding in existing markets. These planning processes must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution and storage facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional electric operating companies or Southern Company Gas' regulated operating companies to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, Southern Company and its subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs and the recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend existing PPAs or find new buyers for existing generation assets as existing PPAs expire, or they may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected registrant.
The traditional electric operating companies are currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-
term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies purchase capacity on the open market or build additional generation and transmission facilities, and for Southern Power to purchase energy or capacity on the open market. Because regulators may not permit the traditional electric operating companies to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power may not be able to recover all of these costs. These situations could have negative impacts on net income and cash flows for the affected registrant.
The businesses of the registrants and Nicor Gas are dependent on their ability to successfully access funds through capital markets and financial institutions. Theinability of any of the registrants or Nicor Gas to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows.
The registrants and Nicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If any of the registrants or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the registrants and Nicor Gas rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of the registrants and Nicor Gas believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain events or market disruptions may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:
an economic downturn or uncertainty;
bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;
capital markets volatility and disruption, either nationally or internationally;
changes in tax policy;
volatility in market prices for electricity and natural gas;
terrorist attacks or threatened attacks on the Southern Company system's facilities or unrelated energy companies' facilities;
war or threat of war; or
the overall health of the utility and financial institution industries.
As of December 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $911 million primarily due to a $900 million unsecured term loan that matures on March 31, 2018. Mississippi Power expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity to fund the remaining indebtedness to mature and other cash needs over the next 12 months.
Georgia Power's ability to make future borrowings through its term loan credit facility with the Federal Financing Bank is subject to the satisfaction of customary conditions, as well as certification of compliance with the requirements of the loan guarantee program under Title XVII of the Energy Policy Act of 2005, including accuracy of project-related representations and warranties, delivery of updated project-related information and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Prior to obtaining any further advances under Georgia Power's loan guarantee agreement with the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement.
Failure to comply with debt covenants or conditions could adversely affect the ability of the registrants, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.
The debt and credit agreements of the registrants, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements, which would negatively affect the applicable company's financial condition and liquidity.
Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning.
The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission Alabama Power's and Georgia Power's nuclear plants. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.
The registrants are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The financial condition of some insurance companies, the threat of terrorism, and natural disasters, among other things, could have disruptive effects on insurance markets. The availability of insurance covering risks that the registrants and their respective competitors typically insure against may decrease, and the insurance that the registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.
Any losses not covered by insurance, or any increases in the cost of applicable insurance, could adversely affect the results of operations, cash flows, or financial condition of the affected registrant.
The use of derivative contracts by Southern Company and its subsidiaries in thenormal course of business could result in financial losses that negatively impact thenet income of the registrants or in reported net income volatility.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage foreign currency exchange rate exposure and engage in limited trading activities. The registrants could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, Southern Company Gas utilizes derivative instruments to lock in economic value in wholesale gas services, which may not qualify or are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income of Southern Company and Southern Company Gas while the positions are open due to mark-to-market accounting.
Future impairments of goodwill or long-lived assets could have a material adverse effect on the registrants' results of operations.
Goodwill is assessed for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or circumstances indicate that an asset's carrying amount may not be recoverable. In connection with the completion of the Merger, the application of the acquisition method of accounting was pushed down to Southern Company Gas. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities was recorded as goodwill. This resulted in a significant increase in the goodwill recorded on Southern Company's and Southern Company Gas' consolidated balance sheets. At December 31, 2017, goodwill was $6.3 billion and $6.0 billion for Southern Company and Southern Company Gas, respectively.
In addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the value of goodwill or long-lived assets become impaired, the affected registrant may be required to incur impairment charges that could have a material impact on their results of operations. For example, a wholly-owned subsidiary of Southern Company
Gas owns and operates a natural gas storage facility consisting of two salt dome caverns where recent seismic mapping indicates that proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. In addition, a subsidiary of Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. With respect to Southern Company's subsidiary's investments in leveraged leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.
| |
Item 1B. | UNRESOLVED STAFF COMMENTS. |
None.
Item 2. PROPERTIES
Electric
Electric Properties
The traditional electric operating companies, Southern Power, and SEGCO, at December 31, 2017, owned and/or operated 33 hydroelectric generating stations, 29 fossil fuel generating stations, three nuclear generating stations, 15 combined cycle/cogeneration stations, 35 solar facilities, eight wind facilities, one biomass facility, and one landfill gas facility. The amounts of capacity for each company, as of December 31, 2017, are shown in the table below.
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
| | (KWs) |
| |
FOSSIL STEAM | | | |
Gadsden | Gadsden, AL | 120,000 |
| |
Gorgas | Jasper, AL | 1,021,250 |
| |
Barry | Mobile, AL | 1,300,000 |
| |
Greene County | Demopolis, AL | 300,000 |
| (2 | ) |
Gaston Unit 5 | Wilsonville, AL | 880,000 |
| |
Miller | Birmingham, AL | 2,532,288 |
| (3 | ) |
Alabama Power Total | | 6,153,538 |
| |
Bowen | Cartersville, GA | 3,160,000 |
| |
Hammond | Rome, GA | 800,000 |
| |
McIntosh | Effingham County, GA | 163,117 |
| |
Scherer | Macon, GA | 750,924 |
| (4 | ) |
Wansley | Carrollton, GA | 925,550 |
| (5 | ) |
Yates | Newnan, GA | 700,000 |
| |
Georgia Power Total | | 6,499,591 |
| |
Crist | Pensacola, FL | 970,000 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (6 | ) |
Scherer Unit 3 | Macon, GA | 204,500 |
| (4 | ) |
Gulf Power Total | | 1,674,500 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (6 | ) |
Greene County | Demopolis, AL | 200,000 |
| (2 | ) |
Watson | Gulfport, MS | 862,000 |
| |
Mississippi Power Total | | 1,562,000 |
| |
Gaston Units 1-4 | Wilsonville, AL | | |
SEGCO Total | | 1,000,000 |
| (7 | ) |
Total Fossil Steam | | 16,889,629 |
| |
NUCLEAR STEAM | | | |
Farley | Dothan, AL | | |
Alabama Power Total | | 1,720,000 |
| |
Hatch | Baxley, GA | 899,612 |
| (8 | ) |
Vogtle Units 1 and 2 | Augusta, GA | 1,060,240 |
| (9 | ) |
Georgia Power Total | | 1,959,852 |
| |
Total Nuclear Steam | | 3,679,852 |
| |
COMBUSTION TURBINES | | | |
Greene County | Demopolis, AL | | |
Alabama Power Total | | 720,000 |
| |
Boulevard | Savannah, GA | 19,700 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
McDonough Unit 3 | Atlanta, GA | 78,800 |
| |
McIntosh Units 1 through 8 | Effingham County, GA | 640,000 |
| |
McManus | Brunswick, GA | 481,700 |
| |
Robins | Warner Robins, GA | 158,400 |
| |
Wansley | Carrollton, GA | 26,322 |
| (5 | ) |
Wilson | Augusta, GA | 354,100 |
| |
Georgia Power Total | | 1,759,022 |
| |
Lansing Smith Unit A | Southport, FL | 39,400 |
| |
Pea Ridge Units 1 through 3 | Pea Ridge, FL | 15,000 |
| |
Gulf Power Total | | 54,400 |
| |
Chevron Cogenerating Station | Pascagoula, MS | 147,292 |
| (10 | ) |
Sweatt | Meridian, MS | 39,400 |
| |
Watson | Gulfport, MS | 39,360 |
| |
Mississippi Power Total | | 226,052 |
| |
Addison | Thomaston, GA | 668,800 |
| |
Cleveland County | Cleveland County, NC | 720,000 |
| |
Dahlberg | Jackson County, GA | 756,000 |
| |
Oleander | Cocoa, FL | 791,301 |
| |
Rowan | Salisbury, NC | 455,250 |
| |
Southern Power Total | | 3,391,351 |
| |
Gaston (SEGCO) | Wilsonville, AL | 19,680 |
| (7 | ) |
Total Combustion Turbines | | 6,170,505 |
| |
COGENERATION | | | |
Washington County | Washington County, AL | 123,428 |
| |
Lowndes County | Burkeville, AL | 104,800 |
| |
Theodore | Theodore, AL | 236,418 |
| |
Alabama Power Total | | 464,646 |
| |
COMBINED CYCLE | | | |
Barry | Mobile, AL | | |
Alabama Power Total | | 1,070,424 |
| |
McIntosh Units 10&11 | Effingham County, GA | 1,318,920 |
| |
McDonough-Atkinson Units 4 through 6 | Atlanta, GA | 2,520,000 |
| |
Georgia Power Total | | 3,838,920 |
| |
Lansing Smith Unit 3 | Southport, FL | | |
Gulf Power Total | | 545,500 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
Daniel | Pascagoula, MS | 1,070,424 |
| |
Kemper County/Ratcliffe | Kemper County, MS | 769,898 |
| (11) |
|
Mississippi Power Total | | 1,840,322 |
| |
Franklin | Smiths, AL | 1,857,820 |
| |
Harris | Autaugaville, AL | 1,318,920 |
| |
Mankato | Mankato, MN | 375,000 |
| |
Rowan | Salisbury, NC | 530,550 |
| |
Stanton Unit A | Orlando, FL | 428,649 |
| (12 | ) |
Wansley | Carrollton, GA | 1,073,000 |
| |
Southern Power Total | | 5,583,939 |
| |
Total Combined Cycle | | 12,879,105 |
| |
HYDROELECTRIC FACILITIES | | | |
Bankhead | Holt, AL | 53,985 |
| |
Bouldin | Wetumpka, AL | 225,000 |
| |
Harris | Wedowee, AL | 132,000 |
| |
Henry | Ohatchee, AL | 72,900 |
| |
Holt | Holt, AL | 46,944 |
| |
Jordan | Wetumpka, AL | 100,000 |
| |
Lay | Clanton, AL | 177,000 |
| |
Lewis Smith | Jasper, AL | 157,500 |
| |
Logan Martin | Vincent, AL | 135,000 |
| |
Martin | Dadeville, AL | 182,000 |
| |
Mitchell | Verbena, AL | 170,000 |
| |
Thurlow | Tallassee, AL | 81,000 |
| |
Weiss | Leesburg, AL | 87,750 |
| |
Yates | Tallassee, AL | 47,000 |
| |
Alabama Power Total | | 1,668,079 |
| |
Bartletts Ferry | Columbus, GA | 173,000 |
| |
Goat Rock | Columbus, GA | 38,600 |
| |
Lloyd Shoals | Jackson, GA | 14,400 |
| |
Morgan Falls | Atlanta, GA | 16,800 |
| |
North Highlands | Columbus, GA | 29,600 |
| |
Oliver Dam | Columbus, GA | 60,000 |
| |
Rocky Mountain | Rome, GA | 215,256 |
| (13 | ) |
Sinclair Dam | Milledgeville, GA | 45,000 |
| |
Tallulah Falls | Clayton, GA | 72,000 |
| |
Terrora | Clayton, GA | 16,000 |
| |
Tugalo | Clayton, GA | 45,000 |
| |
Wallace Dam | Eatonton, GA | 321,300 |
| |
Yonah | Toccoa, GA | 22,500 |
| |
6 Other Plants | Various Georgia locations | 18,080 |
| |
Georgia Power Total | | 1,087,536 |
| |
Total Hydroelectric Facilities | | 2,755,615 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
RENEWABLE SOURCES: | | | |
SOLAR FACILITIES | | | |
Fort Benning | Columbus, GA | 30,000 |
| |
Fort Gordon | Augusta, GA | 30,000 |
| |
Fort Stewart | Fort Stewart, GA | 30,000 |
| |
Kings Bay | Camden County, GA | 30,000 |
| |
Dalton | Dalton, GA | 6,012 |
| |
3 Other Plants | Various Georgia locations | 2,984 |
| |
Georgia Power Total | | 128,996 |
| |
Adobe | Kern County, CA | 20,000 |
| |
Apex | North Las Vegas, NV | 20,000 |
| |
Boulder I | Clark County, NV | 100,000 |
| (14 | ) |
Butler | Taylor County, GA | 103,700 |
| |
Butler Solar Farm | Taylor County, GA | 22,000 |
| |
Calipatria | Imperial County, CA | 20,000 |
| |
Campo Verde | Imperial County, CA | 147,420 |
| |
Cimarron | Springer, NM | 30,640 |
| |
Decatur County | Decatur County, GA | 20,000 |
| |
Decatur Parkway | Decatur County, GA | 84,000 |
| |
Desert Stateline | San Bernadino County, CA | 299,900 |
| (14 | ) |
East Pecos | Pecos County, TX | 120,000 |
| |
Garland | Kern County, CA | 205,130 |
| (14 | ) |
Granville | Oxford, NC | 2,500 |
| |
Henrietta | Kings County, CA | 102,000 |
| (14 | ) |
Imperial Valley | Imperial County, CA | 163,200 |
| (14 | ) |
Lamesa | Dawson County, TX | 102,000 |
| |
Lost Hills - Blackwell | Kern County, CA | 33,440 |
| (14 | ) |
Macho Springs | Luna County, NM | 55,000 |
| |
Morelos del Sol | Kern County, CA | 15,000 |
| |
North Star | Fresno County, CA | 61,600 |
| (14 | ) |
Pawpaw | Taylor County, GA | 30,480 |
| |
Roserock | Pecos County, TX | 160,000 |
| (14 | ) |
Rutherford | Rutherford County, NC | 74,800 |
| |
Sandhills | Taylor County, GA | 146,890 |
| |
Spectrum | Clark County, NV | 30,240 |
| |
Tranquillity | Fresno County, CA | 205,300 |
| (14 | ) |
Southern Power Total | | 2,375,240 |
| (15 | ) |
Total Solar | | 2,504,236 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
WIND FACILITIES | | | |
Bethel | Castro County, TX | 276,000 |
| |
Grant Plains | Grant County, OK | 147,200 |
| |
Grant Wind | Grant County, OK | 151,800 |
| |
Kay Wind | Kay County, OK | 299,000 |
| |
Passadumkeag | Penobscot County, ME | 42,900 |
| |
Salt Fork | Donley & Gray Counties TX | 174,000 |
| |
Tyler Bluff | Cooke County, TX | 125,580 |
| |
Wake Wind | Crosby & Floyd Counties, TX | 257,250 |
| (14 | ) |
Southern Power Total | | 1,473,730 |
| |
LANDFILL GAS FACILITY | | | |
Perdido | Escambia County, FL | | |
Gulf Power Total | | 3,200 |
| |
BIOMASS FACILITY | | | |
Nacogdoches | Sacul, TX | | |
Southern Power Total | | 115,500 |
| |
Total Generating Capacity | | 46,936,018 |
| |
Notes:
|
| |
(1) | See "Jointly-Owned Facilities" herein for additional information. |
(2) | Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively. |
(3) | Capacity shown is Alabama Power's portion (95.92%) of total plant capacity. |
(4) | Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3. |
(5) | Capacity shown is Georgia Power's portion (53.5%) of total plant capacity. |
(6) | Represents 50% of Plant Daniel Units 1 and 2, which are owned as tenants in common by Gulf Power and Mississippi Power. |
(7) | SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information. |
(8) | Capacity shown is Georgia Power's portion (50.1%) of total plant capacity. |
(9) | Capacity shown is Georgia Power's portion (45.7%) of total plant capacity. |
(10) | Generation is dedicated to a single industrial customer. |
(11) | The capacity shown is the gross capacity using natural gas fuel without supplemental firing. |
(12) | Capacity shown is Southern Power's portion (65%) of total plant capacity. |
(13) | Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant. |
(14) | Each facility is owned by Southern Power through a majority-owned subsidiary (90.1% Wake Wind, 66% Desert Stateline, and 51% for each of the following facilities: Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills-Blackwell, North Star, Roserock, and Tranquillity). The capacity shown in the table is 100% of the nameplate capacity for the respective facility. |
(15) | Southern Power is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets, which, if successful, is expected to close in the middle of 2018. |
Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition, and suitable for their intended purpose.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is
paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2017, the unamortized portion of this cost was approximately $13 million.
Mississippi Power owns a lignite mine and equipment that were intended to provide fuel for the Kemper IGCC. Mississippi Power also has acquired mineral reserves located around the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation activities to begin in 2018. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" in Item 8 herein for additional information on the lignite mine.
In 2018, Mississippi Power will file a reserve margin plan which could impact Mississippi Power's generating stations as well as the generating stations jointly owned by Mississippi Power and other traditional electric operating companies. See BUSINESS in Item 1 herein under "Rate Matters – Integrated Resource Planning – Mississippi Power" for additional information.
In 2017, the maximum demand on the traditional electric operating companies, Southern Power, and SEGCO was 34,874,000 KWs and occurred on August 17, 2017. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power, and SEGCO in 2017 was 30.8%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information.
Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power at December 31, 2017 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Percentage Ownership |
| | Total Capacity | | Alabama Power | | Power South | | Georgia Power | | OPC | | MEAG Power | | Dalton | | | Southern Power | | OUC | | FMPA | | KUA |
| | (MWs) | | | | | | | | | | | | | | | | | | | | | |
Plant Miller Units 1 and 2 | | 1,320 |
| | 91.8 | % | | 8.2 | % | | — | % | | — | % | | — | % | | — | % | | | — | % | | — | % | | — | % | | — | % |
Plant Hatch | | 1,796 |
| | — |
| | — |
| | 50.1 |
| | 30.0 |
| | 17.7 |
| | 2.2 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Vogtle Units 1 and 2 | | 2,320 |
| | — |
| | — |
| | 45.7 |
| | 30.0 |
| | 22.7 |
| | 1.6 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Scherer Units 1 and 2 | | 1,636 |
| | — |
| | — |
| | 8.4 |
| | 60.0 |
| | 30.2 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Wansley | | 1,779 |
| | — |
| | — |
| | 53.5 |
| | 30.0 |
| | 15.1 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Rocky Mountain | | 848 |
| | — |
| | — |
| | 25.4 |
| | 74.6 |
| | — |
| | — |
| | | — |
| | — |
| | — |
| | — |
|
Plant Stanton A | | 660 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 65.0 |
| | 28.0 |
| | 3.5 |
| | 3.5 |
|
Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power's nuclear plants.
In addition, Georgia Power has commitments regarding a portion of a 5% interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC's disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power's statements of income in Item 8 herein. Also see Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 herein for additional information.
Construction continues on Plant Vogtle Units 3 and 4, which are jointly owned by the Vogtle Owners (with each owner holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein.
Titles to Property
The traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants (other than certain pollution control facilities and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the (1) liens pursuant to pollution control revenue bonds of Gulf Power on specific pollution control facilities at Plant Daniel, (2) liens pursuant to the assumption of debt obligations by Mississippi Power in connection with the acquisition of Plant Daniel Units 3 and 4, (3) liens pursuant to the agreements entered into with Mississippi Power's largest customer, Chevron Products Company (Chevron), on October 4, 2017, on the co-generation assets located at the Chevron refinery, (4) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4, and (5) liens associated with two PPAs assumed as part of the acquisition of the Mankato project in October 2016 by Southern Power Company. See Note 6 to the financial statements of Southern Company, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under "Assets Subject to Lien," Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings," and Note 6 to the financial statements of Southern Company and Mississippi Power under "Plant Daniel Revenue Bonds" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.
Natural Gas
Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 6 to the financial statements of Southern Company Gas under "Long-Term Debt – First Mortgage Bonds" in Item 8 herein for additional information.
Distribution and Transmission Mains – Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2017, Southern Company Gas' gas distribution operations segment owned approximately 82,000 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.
Storage Assets – Gas Distribution Operations– Southern Company Gas owns and operates eight underground natural gas storage facilities in Illinois with a total inventory capacity of approximately 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.
Southern Company Gas also has five liquefied natural gas (LNG) plants located in Georgia, New Jersey, and Tennessee with total LNG storage capacity of approximately 7.6 Bcf. In addition, Southern Company Gas owns one propane storage facility in Virginia with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.
Storage Assets – All Other– Southern Company Gas subsidiaries own three high-deliverability natural gas storage and hub facilities that are operated by the gas midstream operations segment. Jefferson Island Storage & Hub, LLC operates a storage facility in Louisiana consisting of two salt dome gas storage caverns. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California. In addition, Southern Company Gas has a LNG facility in Alabama that produces LNG for Pivotal LNG, Inc. to support its business of selling LNG as a substitute fuel in various markets.
In August 2017, in connection with an ongoing integrity project into the salt dome gas storage caverns in Louisiana, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note 3 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
Jointly-Owned Properties– Southern Company Gas' gas midstream operations segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia that was placed in service on August 1, 2017. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 4 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of legal and administrative proceedings discussed therein.
| |
Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
Age 60
Elected in 2003. Chairman and Chief Executive Officer since December 2010 and President since August 2010.
Art P. Beattie
Executive Vice President and Chief Financial Officer
Age 63
Elected in 2010. Executive Vice President and Chief Financial Officer since August 2010.
W. Paul Bowers
Executive Vice President
Age 61
Elected in 2001. Executive Vice President since February 2008 and Chief Executive Officer, President, and Director of Georgia Power since January 2011. Chairman of Georgia Power's Board of Directors since May 2014.
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer of Gulf Power
Age 48
Elected in 2012. Elected Chairman in July 2015 and President, Chief Executive Officer, and Director of Gulf Power since July 2012.
Mark A. Crosswhite
Executive Vice President
Age 55
Elected in 2010. Executive Vice President since July 2012 and President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.
Andrew W. Evans
Executive Vice President
Age 51
Elected in July 2016. Executive Vice President since July 2016. President of Southern Company Gas since May 2015 and Chief Executive Officer and Chairman of Southern Company Gas' Board of Directors since January 2016. Previously served as Chief Operating Officer of Southern Company Gas from May 2015 through December 2015 and Executive Vice President and Chief Financial Officer of Southern Company Gas from May 2006 through May 2015.
Kimberly S. Greene
Executive Vice President
Age 51
Elected in 2013. Executive Vice President and Chief Operating Officer since March 2014. Director of Southern Company Gas since July 2016. Previously served as President and Chief Executive Officer of SCS from April 2013 to February 2014. Before rejoining Southern Company, Ms. Greene served at Tennessee Valley Authority as Executive Vice President and Chief Generation Officer from 2011 through April 2013.
James Y. Kerr II
Executive Vice President and General Counsel
Age 53
Elected in 2014. Also serves as Chief Compliance Officer. Before joining Southern Company, Mr. Kerr was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC from 2008 through February 2014.
Stephen E. Kuczynski
Chairman, President, and Chief Executive Officer of Southern Nuclear
Age 55
Elected in 2011. Chairman, President, and Chief Executive Officer of Southern Nuclear since July 2011.
Mark S. Lantrip
Executive Vice President
Age 63
Elected in 2014. Chairman, President, and Chief Executive Officer of SCS since March 2014. Previously served as Treasurer of Southern Company from October 2007 to February 2014 and Executive Vice President of SCS from November 2010 to March 2014.
Nancy E. Sykes
Executive Vice President of SCS
Age 49
Elected in 2016. Also serves as Chief Human Resources Officer of SCS. Before joining Southern Company, Ms. Sykes served as vice president and chief human resources officer at United States Steel Corporation from May 2015 to November 2016. Previously served as Vice President, Human Resources Asia-Pacific at Goodyear Tire and Rubber Company from October 2012 until May 2015.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer of Mississippi Power
Age 53
Elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016. Previously served as Executive Vice President of Mississippi Power from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.
Christopher C. Womack
Executive Vice President
Age 59
Elected in 2008. Executive Vice President and President of External Affairs since January 2009.
The officers of Southern Company were elected at the first meeting of the directors following the last annual meeting of stockholders held on May 24, 2017, for a term of one year or until their successors are elected and have qualified.
EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer
Age 55
Elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.
Greg J. Barker
Executive Vice President
Age 54
Elected in 2016. Executive Vice President for Customer Services since February 2016. Previously served as Senior Vice President of Marketing and Economic Development from April 2012 to February 2016.
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
Age 58
Elected in 2010. Executive Vice President, Chief Financial Officer, and Treasurer since August 2010.
Zeke W. Smith
Executive Vice President
Age 58
Elected in 2010. Executive Vice President of External Affairs since November 2010.
James P. Heilbron
Senior Vice President and Senior Production Officer
Age 46
Elected in 2013. Senior Vice President and Senior Production Officer since March 2013. Previously served as Senior Vice President and Senior Production Officer of Southern Power Company from July 2010 to February 2013.
R. Scott Moore
Senior Vice President
Age 50
Elected in 2017. Senior Vice President of Power Delivery since May 2017. Previously served as Vice President of Transmission from August 2012 to May 2017.
The officers of Alabama Power were elected at the meeting of the directors held on April 28, 2017 for a term of one year or until their successors are elected and have qualified, except for Mr. Moore, whose election as Senior Vice President was effective May 20, 2017.
EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer
Age 53
Elected in 2015. President since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board since August 2016. Previously served as Executive Vice President from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.
John W. Atherton
Vice President
Age 57
Elected in 2004. Vice President of Corporate Services and Community Relations since October 2012.
A. Nicole Faulk
Vice President
Age 44
Elected in 2015. Vice President of Customer Services Organization effective April 2015. Previously served as Region Vice President for the West Region of Georgia Power from March 2015 through April 2015 and Region Manager for the Metro West Region of Georgia Power from December 2011 to March 2015.
Moses H. Feagin
Vice President, Treasurer, and Chief Financial Officer
Age 53
Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 2010.
R. Allen Reaves, Jr.
Vice President
Age 58
Elected in 2010. Vice President and Senior Production Officer since August 2010.
Billy F. Thornton
Vice President
Age 57
Elected in 2012. Vice President of External Affairs since October 2012.
The officers of Mississippi Power were elected at the meeting of the directors held on May 1, 2017 for a term of one year or until their successors are elected and have qualified.
PART II
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Item 5. | MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
(a)(1) The common stock of Southern Company is listed and traded on the NYSE. The common stock is also traded on regional exchanges across the U.S. The high and low stock prices as reported on the NYSE for each quarter of the past two years were as follows:
|
| | | | | | | | |
| | High | | Low |
2017 | | | | |
First Quarter | | $ | 51.47 |
| | $ | 47.57 |
|
Second Quarter | | 51.97 |
| | 47.87 |
|
Third Quarter | | 50.80 |
| | 46.71 |
|
Fourth Quarter | | 53.51 |
| | 47.92 |
|
2016 | | | | |
First Quarter | | $ | 51.73 |
| | $ | 46.00 |
|
Second Quarter | | 53.64 |
| | 47.62 |
|
Third Quarter | | 54.64 |
| | 50.00 |
|
Fourth Quarter | | 52.23 |
| | 46.20 |
|
There is no market for the other registrants' common stock, all of which is owned by Southern Company.
(a)(2) Number of Southern Company's common stockholders of record at January 31, 2018: 120,413
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrant's common stock are payable at the discretion of their respective board of directors and depend upon earnings, financial condition, and other factors. The dividends on common stock declared by Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, and Southern Company Gas to their stockholder(s) for the past two years are set forth below. No dividends were declared by Mississippi Power on its common stock in 2016 or 2017. Southern Company Gas' dividends are only shown for periods subsequent to the Merger.
|
| | | | | | | | | | |
Registrant | | Quarter | | 2017 | | 2016 |
| | | | (in thousands) |
Southern Company | | First | | $ | 555,791 |
| | $ | 496,718 |
|
| | Second | | 578,525 |
| | 526,267 |
|
| | Third | | 581,501 |
| | 529,876 |
|
| | Fourth | | 584,015 |
| | 551,110 |
|
Alabama Power | | First | | 178,507 |
| | 191,206 |
|
| | Second | | 178,507 |
| | 191,206 |
|
| | Third | | 178,507 |
| | 191,206 |
|
| | Fourth | | 178,507 |
| | 191,206 |
|
Georgia Power | | First | | 320,242 |
| | 326,269 |
|
| | Second | | 320,242 |
| | 326,269 |
|
| | Third | | 320,242 |
| | 326,269 |
|
| | Fourth | | 320,242 |
| | 326,269 |
|
Gulf Power | | First | | 31,250 |
| | 30,017 |
|
| | Second | | 31,250 |
| | 30,017 |
|
| | Third | | 31,250 |
| | 30,017 |
|
| | Fourth | | 71,250 |
| | 30,017 |
|
Southern Power Company | | First | | 79,211 |
| | 68,082 |
|
| | Second | | 79,211 |
| | 68,082 |
|
| | Third | | 79,211 |
| | 68,082 |
|
| | Fourth | | 79,211 |
| | 68,082 |
|
Southern Company Gas | | First | | 110,641 |
| | — |
|
| | Second | | 110,641 |
| | — |
|
| | Third | | 110,641 |
| | 62,750 |
|
| | Fourth | | 110,641 |
| | 62,750 |
|
The dividend paid per share of Southern Company's common stock was 56.00¢ for the first quarter 2017 and 58.00¢ each for the second, third, and fourth quarters of 2017. In 2016, Southern Company paid a dividend per share of 54.25¢ for the first quarter and 56.00¢ each for the second, third, and fourth quarters.
The traditional electric operating companies and Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. The authority of the natural gas distribution utilities to pay dividends to Southern Company Gas is subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates. Additionally, Elizabethtown Gas is restricted by its policy, as established by the New Jersey Board of Public Utilities, to 70% of its quarterly net income it can dividend to Southern Company Gas. Also, as stipulated in the New Jersey Board of Public Utilities' order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade.
(a)(4) Securities authorized for issuance under equity compensation plans.
See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
| |
Item 6. | SELECTED FINANCIAL DATA |
| |
Item 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
| |
Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each of the registrants in Item 7 herein and Note 1 of each of the registrant's financial statements under "Financial Instruments" in Item 8 herein. See also Notes 10 and 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Notes 9 and 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Notes 8 and 9 to the financial statements of Southern Power in Item 8 herein.
| |
Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO 2017 FINANCIAL STATEMENTS
| |
Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| |
Item 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures.
As of the end of the period covered by this Annual Report on Form 10-K, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
(a) Management's Annual Report on Internal Control Over Financial Reporting.
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Management's Report on Internal Control Over Financial Reporting | Page |
| |
| |
| |
| |
| |
| |
| |
(b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Company's independent registered public accounting firm, regarding Southern Company's Internal Control over Financial Reporting is included on page II-9 of this Form 10-K. This report is not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas as these companies are not accelerated filers or large accelerated filers.
(c) Changes in internal control over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the fourth quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
| |
Item 9B. | OTHER INFORMATION |
None.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2017 Annual Report
The management of The Southern Company (Southern Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 2017.
Deloitte & Touche LLP, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 2017, which is included herein.
/s/ Thomas A. Fanning
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President and Chief Financial Officer
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements (pages II-64 to II-151) referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting (page II-8). Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to increased retail revenues.error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 20, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of Mississippi Power's Kemper County energy facility |
2013 ARP | Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
AFUDC | Allowance for funds used during construction |
Alabama Power | Alabama Power Company |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest |
Bechtel | Bechtel Power Corporation |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
COD | Commercial operation date |
Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
Cooperative Energy | Electric cooperative in Mississippi |
CPCN | Certificate of public convenience and necessity |
CWIP | Construction work in progress |
Dalton Pipeline | A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest |
DOE | U.S. Department of Energy |
Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FFB | Federal Financing Bank |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe) |
Interim Assessment Agreement | Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
LIFO | Last-in, first-out |
Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
LTSA | Long-term service agreement |
Merger | The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation |
Mirror CWIP | A regulatory liability used by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility, which were subsequently refunded to customers |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MPUS | Mississippi Public Utilities Staff |
MW | Megawatt |
natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Inc., Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) |
NCCR | Georgia Power's Nuclear Construction Cost Recovery |
NDR | Alabama Power's Natural Disaster Reserve |
New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
PennEast Pipeline | PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest |
PowerSecure | PowerSecure, Inc. |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PSC | Public Service Commission |
PTC | Production tax credit |
Rate CNP | Alabama Power's Rate Certificated New Plant |
Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Alabama Power's Rate Energy Cost Recovery |
Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
SO2 | Sulfur dioxide |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | The Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries |
Southern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
Toshiba | Toshiba Corporation, parent company of Westinghouse |
Toshiba Guarantee | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
VCM | Vogtle Construction Monitoring |
Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
Vogtle Services Agreement | The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear |
Westinghouse | Westinghouse Electric Company LLC |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2017 Annual Report
OVERVIEW
Business Activities
The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. See FUTURE EARNINGS POTENTIAL – "General" herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
Many factors affect the opportunities, challenges, and risks of the Southern Company system's electricity and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems.
The traditional electric operating companies and natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 3 to the financial statements under "Regulatory Matters" for additional information.
Another major factor affecting the Southern Company system's businesses is the profitability of the competitive market-based wholesale generating business. Southern Power's strategy is to create value through various transactions including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities. Southern Power is also currently pursuing the sale of a portion of equity interests in its solar assets. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.
In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than nine million electric and gas utility customers, the Southern Company system continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share (EPS). Southern Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system.
See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Kemper County Energy Facility Status
The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Energy Sales
Changesthe CO2 pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in revenues are influenced heavily byservice in August 2014. In December 2015, the changeMississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the volumeMississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket).
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy sold from yearfacility, given the uncertainty as to year. KWH salesits future. At the time of project suspension, the total cost estimate for 2015the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the percent change$137 million in additional grants from the prior year wereDOE received on April 8, 2016 (Additional DOE Grants). In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as follows:
|
| | | | | | | | | | | | | | |
| Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2015 | | 2015 | | 2014 | | 2015* | | 2014 |
| (in billions) | | | | | | | | |
Residential | 52.1 |
| | (2.3 | )% | | 5.5 | % | | 0.4 | % | | — | % |
Commercial | 53.5 |
| | 0.5 |
| | 1.3 |
| | 0.9 |
| | (0.4 | ) |
Industrial | 54.0 |
| | (0.4 | ) | | 3.3 |
| | (0.3 | ) | | 3.3 |
|
Other | 0.9 |
| | (1.4 | ) | | 0.9 |
| | (1.3 | ) | | 0.7 |
|
Total retail | 160.5 |
| | (0.7 | ) | | 3.3 |
| | 0.3 | % | | 0.9 | % |
Wholesale | 30.5 |
| | (7.0 | ) | | 21.7 |
| | | | |
Total energy sales | 191.0 |
| | (1.8 | )% | | 6.0 | % | | | | |
|
| |
* | In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of Mississippi Power's unbilled 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, 2015 weather-adjusted commercial sales increased 0.8% and industrial KWH sales decreased 0.4% as compared to the corresponding period in 2014. |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changesthe cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in weather,June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and changeslignite mine.
On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with Mississippi Power's Performance Evaluation Plan (PEP), excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the number of customers. RetailKemper County energy sales decreased 1.2 billion KWHsfacility requested for inclusion in 2015 as compared to the prior year. This decreaserate base, which was primarily the result of milder weatherrecorded in the firstfourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third and fourth quarters of 20152017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as comparedwell as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the corresponding periods in 2014 and decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased primarily due to customer growth and increased customer usage. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage.Household income, oneKemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of the primary drivers of residential customer usage, had modest growth in 2015. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, and paper sectors, partially offset by increased sales in the transportation, stone, clay, and glass, pipeline, lumber, and petroleum sectors. A strong dollar, low oil prices, and weak global economic growth conditions constrained the industrial sector in 2015.$6.2 billion ($4.1 billion after tax) through December 31, 2017.
Retail energy sales increased 5.2 billion KWHs in 2014 as compared to the prior year. This increase was primarily the result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and customer growth, partially offset by a decrease in customer usage. The increase in industrial KWH energy sales was primarily due to increased sales in the primary metals, chemicals, paper, non-manufacturing, transportation, and stone, clay, and glass sectors. Weather-adjusted commercial KWH energy sales decreased primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH energy sales were flat compared to the prior year asAs a result of customer growth offset by decreased customer usage. Household income, onethe Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the primary driverstwo AP1000 nuclear units (with electric generating capacity of residential customer usage, was flat in 2014.
See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenuesapproximately 1,100 MWs each) and related facilities to changes in price and KWH sales.begin. Until March 2017, construction on Plant Vogtle Units
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Details3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
See Note 3 to the financial statements under "Nuclear Construction" for additional information.
Earnings
Consolidated net income attributable to Southern Company was $842 million in 2017, a decrease of $1.6 billion, or 65.6%, from the prior year. The decrease was primarily due to pre-tax charges of $3.4 billion ($2.4 billion after tax) related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases of $240 million in net income from Southern Company Gas (excluding the impact of $111 million in additional expense related to the Tax Reform Legislation) reflecting the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, $264 million related to net tax benefits from the Tax Reform Legislation, higher retail electric revenues resulting from increases in base rates partially offset by milder weather and lower customer usage, and increases in renewable energy sales at Southern Power. These increases were partially offset by higher interest and depreciation and amortization.
Consolidated net income attributable to Southern Company was $2.4 billion in 2016, an increase of $81 million, or 3.4%, from the prior year. Consolidated net income increased by $114 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016. Also contributing to the increase were higher retail electric revenues resulting from non-fuel retail rate increases and warmer weather, primarily in the third quarter 2016, as well as the 2015 correction of a Georgia Power billing error, partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. Additionally, the increase was due to increases in income tax benefits and renewable energy sales at Southern Power. These increases were partially offset by higher interest expense, non-fuel operations and maintenance expenses, depreciation and amortization, lower wholesale capacity revenues, and higher estimated losses associated with the Kemper IGCC.
See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Basic EPS was $0.84 in 2017, $2.57 in 2016, and $2.60 in 2015. Diluted EPS, which factors in additional shares related to stock-based compensation, was $0.84 in 2017, $2.55 in 2016, and $2.59 in 2015. EPS for 2017 was negatively impacted by $0.04 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.30 in 2017, $2.22 in 2016, and $2.15 in 2015. In January 2018, Southern Company declared a quarterly dividend of 58 cents per share. This is the 281st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2017, the dividend payout ratio was 273% compared to 86% for 2016. The increase was due to a significant reduction in earnings resulting from charges related to the Kemper IGCC. See "Earnings" and RESULTS OF OPERATIONS – "Electricity Business – Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
RESULTS OF OPERATIONS
Discussion of the results of operations is divided into three parts – the Southern Company system's generationprimary business of electricity sales, its gas business, and purchased powerits other business activities.
|
| | | | | | | | | | | |
| Amount |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Electricity business | $ | 878 |
| | $ | 2,571 |
| | $ | 2,401 |
|
Gas business | 243 |
| | 114 |
| | — |
|
Other business activities | (279 | ) | | (237 | ) | | (34 | ) |
Net Income | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Electricity Business
Southern Company's electric utilities generate and sell electricity to retail and wholesale customers.
A condensed statement of income for the electricity business follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 | | 2016 |
| (in millions) |
Electric operating revenues | $ | 18,540 |
| | $ | 599 |
| | $ | 499 |
|
Fuel | 4,400 |
| | 39 |
| | (389 | ) |
Purchased power | 863 |
|
| 113 |
| | 105 |
|
Cost of other sales | 69 |
| | 11 |
| | 58 |
|
Other operations and maintenance | 4,340 |
| | (183 | ) | | 231 |
|
Depreciation and amortization | 2,457 |
| | 224 |
| | 213 |
|
Taxes other than income taxes | 1,063 |
| | 24 |
| | 44 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 2,934 |
| | 63 |
|
Total electric operating expenses | 16,554 |
| | 3,162 |
| | 325 |
|
Operating income | 1,986 |
| | (2,563 | ) | | 174 |
|
Allowance for equity funds used during construction | 152 |
| | (48 | ) | | (26 | ) |
Interest expense, net of amounts capitalized | 1,011 |
| | 80 |
| | 157 |
|
Other income (expense), net | (83 | ) | | (8 | ) | | (43 | ) |
Income taxes | 82 |
| | (1,009 | ) | | (235 | ) |
Net income | 962 |
| | (1,690 | ) | | 183 |
|
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | (7 | ) | | (9 | ) |
Net income attributable to noncontrolling interests | 46 |
| | 10 |
| | 22 |
|
Net Income Attributable to Southern Company | $ | 878 |
| | $ | (1,693 | ) | | $ | 170 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Electric Operating Revenues
Electric operating revenues for 2017 were $18.5 billion, reflecting a $599 million increase from 2016. Details of electric operating revenues were as follows:
|
| | | | | | | | |
| 2015 | | 2014 | | 2013 |
Total generation (billions of KWHs) | 187 |
| | 191 |
| | 179 |
|
Total purchased power (billions of KWHs) | 13 |
| | 12 |
| | 12 |
|
Sources of generation (percent) — | | | | | |
Coal | 34 |
| | 42 |
| | 39 |
|
Nuclear | 16 |
| | 16 |
| | 17 |
|
Gas | 46 |
| | 39 |
| | 40 |
|
Hydro | 3 |
| | 3 |
| | 4 |
|
Other Renewables | 1 |
| | — |
| | — |
|
Cost of fuel, generated (cents per net KWH) — | | | | | |
Coal | 3.55 |
| | 3.81 |
| | 4.01 |
|
Nuclear | 0.79 |
| | 0.87 |
| | 0.87 |
|
Gas | 2.60 |
| | 3.63 |
| | 3.29 |
|
Average cost of fuel, generated (cents per net KWH) | 2.64 |
| | 3.25 |
| | 3.17 |
|
Average cost of purchased power (cents per net KWH)* | 6.11 |
| | 7.13 |
| | 5.27 |
|
|
| |
* | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
In 2015, total fuel and purchased power expenses were $5.4 billion, a decrease of $1.3 billion, |
| | | | | | | |
| Amount |
| 2017 | | 2016 |
| (in millions) |
Retail electric — prior year | $ | 15,234 |
| | $ | 14,987 |
|
Estimated change resulting from — | | | |
Rates and pricing | 508 |
| | 427 |
|
Sales decline | (71 | ) | | (35 | ) |
Weather | (281 | ) | | 153 |
|
Fuel and other cost recovery | (60 | ) | | (298 | ) |
Retail electric — current year | 15,330 |
| | 15,234 |
|
Wholesale electric revenues | 2,426 |
| | 1,926 |
|
Other electric revenues | 681 |
| | 698 |
|
Other revenues | 103 |
| | 83 |
|
Electric operating revenues | $ | 18,540 |
| | $ | 17,941 |
|
Percent change | 3.3 | % | | 2.9 | % |
Retail electric revenues increased $96 million, or 19.2%0.6%, in 2017 as compared to the prior year. The decrease was primarily the result of a $1.1 billion decreasesignificant factors driving this change are shown in the average cost of fuelpreceding table. The increase in rates and purchased powerpricing in 2017 was primarily due to lower coala Rate RSE increase at Alabama Power effective in January 2017, the recovery of Plant Vogtle Units 3 and natural gas prices4 construction financing costs under the NCCR tariff at Georgia Power, and a $137 million net decrease in the volume of KWHs generated and purchased due to milder weather in the first and fourth quarters of 2015.
In 2014, total fuel and purchased power expenses were $6.7 billion, an increase of $706in retail base rates effective July 2017 at Gulf Power. See Note 3 to the financial statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.
Retail electric revenues increased $247 million, or 11.8%1.6%, in 2016 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was primarily due to increases in base tariffs at Georgia Power under the result2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the 2015 correction of an error affecting billings since 2013 to a $422 million increasesmall number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power and the implementation of rates at Mississippi Power for certain Kemper County energy facility in-service assets, effective September 2015. These increases were partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. See Note 3 to the financial statements under "Kemper County Energy Facility – Rate Recovery" for additional information.
See Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate RSE" and " – Rate CNP Compliance" and "Nuclear Construction" and Note 1 to the financial statements under "General" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of KWHs generatedenergy sold, including changes related to sales decline and weather.
Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale electric revenues consist of PPAs primarily duewith investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to increased demand resulting from colder weather innet income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the first quarter 2014 and warmer weather in the second and third quarters 2014 asmarket prices of wholesale energy compared to the corresponding periodsSouthern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in 2013 and a $286 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.
Fuel and purchased power energy transactions at the traditional operating companiesrevenues that are generally offsetdriven by fuel revenuesprices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power'sEnergy sales from solar and wind PPAs are generally the responsibility of the counterparties and do not significantly impact net income.have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a
Fuel
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
result, the Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
Wholesale electric revenues from power sales were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Capacity and other | $ | 838 |
| | $ | 771 |
| | $ | 875 |
|
Energy | 1,588 |
| | 1,155 |
| | 923 |
|
Total | $ | 2,426 |
| | $ | 1,926 |
| | $ | 1,798 |
|
In 2015, fuel expense was $4.8 billion, a decrease of $1.3 billion,2017, wholesale revenues increased $500 million, or 20.9%26.0%, as compared to the prior year.year due to a $433 million increase in energy revenues and a $67 million increase in capacity revenues, primarily at Southern Power. The decreaseincrease in energy revenues was primarily due to increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to a 28.4% decrease in the average cost ofPPA related to new natural gas per KWH generated, a 19.2% decrease in the volume of KWHs generated by coal,facilities and a 6.8% decrease in the average cost of coal per KWH generated, partially offset by a 15.9% increase in the volume of KWHs generated by natural gas.additional customer capacity requirements.
In 2014, fuel expense was $6.0 billion, an increase of $4952016, wholesale revenues increased $128 million, or 9.0%7.1%, as compared to the prior year.year due to a $232 million increase in energy revenues, partially offset by a $104 million decrease in capacity revenues. The increase in energy revenues was primarily due to a 12.7% increaseincreases in the volume of KWHs generated by coal, a 10.3% increase in the average cost of natural gas per KWH generated,short-term sales and a 30.7% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall,renewable energy sales at Southern Power, partially offset by a 5.0%lower fuel prices. The decrease in capacity revenues was primarily due to the average costexpiration of coal per KWH generated.wholesale contracts at Georgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power in the first quarter 2016.
Purchased Power
|
| | | | |
Facility/Source | Counterparty | MWs |
| Contract Term |
NCEMC | NCEMC | 100 |
| through Dec. 2021 |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" and "Acquisitions" of Southern Power in Item 7 herein and Note 11 to the financial statements of Southern Power in Item 8 herein for additional information.
For the year ended December 31, 2017, approximately 11.3% of Southern Power's revenues were derived from Georgia Power. Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.
Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas marketing services, wholesale gas services, and gas midstream operations.
Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains 82,000 miles of natural gas pipelines and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.6 million customers across seven states and has rates of return that are regulated by each individual state in return for exclusive franchises.
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings Inc., entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey Board of Public Utilities, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey Board of Public Utilities and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018. The ultimate outcome of these matters cannot be determined at this time.
Gas marketing services is comprised of SouthStar Energy Services, LLC (SouthStar) and Nicor Energy Services Company (doing business as Pivotal Home Solutions) and provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice. SouthStar, serving approximately 774,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management. Pivotal Home Solutions, serving approximately 1.2 million service contracts, provides a suite of home protection products and services that offers homeowners predictability regarding their energy service delivery, systems, and appliances.
Wholesale gas services consists of Sequent Energy Management, L.P. and engages in natural gas storage and gas pipeline arbitrage and provides natural gas asset management and related logistical services to most of the natural gas distribution utilities as well as non-affiliate companies.
Gas midstream operations includes joint ventures in pipeline investments (including a 50% ownership interest in Southern Natural Gas Company, L.L.C. and two significant pipeline construction projects) as well as a 50% joint ownership in a significant pipeline project and wholly-owned natural gas storage facilities that enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Southern Natural Gas Company, L.L.C. is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.
For additional information on Southern Company Gas' business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Other Businesses
PowerSecure, which was acquired by Southern Company in May 2016, provides products and services in the areas of distributed energy infrastructure, energy efficiency, and utility infrastructure.
Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and also for other electric and natural gas products and services.
Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public. Southern Linc delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square miles in the Southeast. Southern Linc also provides fiber optics services within the Southeast through its subsidiary, Southern Telecom, Inc.
These efforts to invest in and develop new business opportunities may offer potential returns exceeding those of rate-regulated operations. However, these activities often involve a higher degree of risk.
Construction Programs
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2018 through 2022, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company, each traditional electric operating company, Southern Power, and Southern Company Gas in Item 7 herein. The Southern Company system's construction program consists of capital investment and capital expenditures to comply with environmental laws and regulations. The traditional electric operating companies also anticipate expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Southern Company system's asset retirement obligation liabilities. In 2018, the construction program is expected to be apportioned approximately as follows:
|
| | | | | | | | | | | | | | | |
| Southern Company system(a)(b) | Alabama Power | Georgia Power(a) | Gulf Power | Mississippi Power |
| (in billions) |
New generation | $ | 1.3 |
| $ | — |
| $ | 1.3 |
| $ | — |
| $ | — |
|
Environmental compliance(c) | 1.1 |
| 0.6 |
| 0.5 |
| 0.1 |
| — |
|
Generation maintenance | 0.9 |
| 0.5 |
| 0.2 |
| 0.1 |
| 0.1 |
|
Transmission | 0.9 |
| 0.3 |
| 0.5 |
| — |
| — |
|
Distribution | 1.2 |
| 0.5 |
| 0.5 |
| 0.1 |
| 0.1 |
|
Nuclear fuel | 0.3 |
| 0.1 |
| 0.2 |
| — |
| — |
|
General plant | 0.5 |
| 0.2 |
| 0.2 |
| — |
| — |
|
| 6.0 |
| 2.2 |
| 3.3 |
| 0.3 |
| 0.2 |
|
Southern Power(d) | 1.3 |
| | | | |
Southern Company Gas(e) | 1.7 |
| | | | |
Other subsidiaries | 0.4 |
| | | | |
Total(a) | $ | 9.4 |
| $ | 2.2 |
| $ | 3.3 |
| $ | 0.3 |
| $ | 0.2 |
|
| |
(a) | Totals may not add due to rounding. |
| |
(b) | Includes the traditional electric operating companies, Southern Power, and Southern Company Gas, as well as the other subsidiaries. See "Other Businesses" herein for additional information. |
| |
(c) | Reflects cost estimates for environmental regulations. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil-fuel-fired electric generating units or costs associated with closure and groundwater monitoring under the CCR Rule. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information. |
| |
(d) | Includes approximately $0.9 billion for planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. |
| |
(e) | Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 herein for additional information. See |
"The Southern Company System – Southern Company Gas" herein for additional information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities. Projected capital expenditures of $0.1 billion related to these two natural gas distribution utilities are excluded from the amounts above.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been previously constructed, which may result in revised estimates during construction. See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4.
Also see "Regulation – Environmental Laws and Regulations" herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Facilities" in Item 2 herein for additional information concerning Alabama Power's, Georgia Power's, and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities and Southern Company Gas' joint ownership of a pipeline facility.
Financing Programs
See each of the registrant's MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 6 to the financial statements of each registrant in Item 8 herein for information concerning financing programs.
Fuel Supply
Electric
The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Electricity Business – Fuel and Purchased Power Expenses" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Fuel and Purchased Power Expenses" of each traditional electric operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2015 through 2017.
The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2018 coal burn requirements. These agreements have terms ranging between one and four years. In 2017, the weighted average sulfur content of all coal burned by the traditional electric operating companies was 1.12%. This sulfur level, along with banked and purchased sulfur dioxide allowances, allowed the traditional electric operating companies to remain within limits set by Phase I of the Cross-State Air Pollution Rule (CSAPR) under the Clean Air Act. In 2017, the Southern Company system did not purchase any sulfur dioxide allowances, annual nitrogen oxide emission allowances, or seasonal nitrogen oxide emission allowances from the market. As any additional environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure that the traditional electric operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each traditional electric operating company, and Southern Power in Item 7 herein for additional information on environmental matters.
SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2018, SCS has contracted for 510 Bcf of natural gas supply under agreements with remaining terms up to 15 years. In addition to natural gas supply, SCS has contracts in place
for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.
Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. The uranium, conversion services, and fuel fabrication contracts are for terms of less than 10 years with varying expiration dates. The term lengths for the enrichment services contracts are for less than 15 years with varying expiration dates. Management believes suppliers have sufficient nuclear fuel production capability to permit the normal operation of the Southern Company system's nuclear generating units.
Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's natural gas and biomass PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.
Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.
Natural Gas
Recent advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and relatively low prices for natural gas. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the state regulatory agencies in which Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and from its wholly-owned subsidiary, Sequent Energy Management, L.P., under asset management agreements in states where such agreements are approved by the applicable state regulatory agency. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.
Territory Served by the Southern Company System
Traditional Electric Operating Companies and Southern Power
The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with the northwestern portion of Florida and southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2017, the territory had an area of approximately 120,000 square miles and an estimated population of approximately 17 million. Southern Power sells electricity at market-based rates in the wholesale market, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.
Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 14 municipally-owned electric distribution systems, 11 of which are served indirectly through sales to the Alabama Municipal Electric Authority, and two rural distributing cooperative associations. Alabama Power owns coal reserves near its Plant Gorgas and uses the output of coal from the reserves in its generating plants. Alabama Power also sells, and cooperates with dealers in promoting the sale of, electric appliances and products and markets and sells outdoor lighting services.
Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services.
Gulf Power is engaged, within the northwestern portion of Florida, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in 71 communities (including Pensacola, Panama City, and Fort Walton Beach), as well as in rural areas, and at wholesale to a non-affiliated utility.
Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.
For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of each traditional electric operating company in Item 7 herein. For information relating to the number of retail customers served by customer classification for the traditional electric operating companies, see SELECTED FINANCIAL DATA of each traditional electric operating company in Item 6 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, reference is made to Item 7 herein.
The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. As of December 31, 2017, there were approximately 62 electric cooperative distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama and northwest Florida. As of December 31, 2017, PowerSouth owned generating units with approximately 2,100 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. PowerSouth's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for details of Alabama Power's joint-ownership with PowerSouth of a portion of Plant Miller. Alabama Power has a system supply agreement with PowerSouth to provide 200 MWs of capacity service through December 31, 2030 with an option to extend and renegotiate in the event Alabama Power builds new generation or contracts for new capacity.
Alabama Power and Gulf Power have entered into separate agreements with PowerSouth involving interconnection between their respective systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territories of Alabama Power and Gulf Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.
OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets and power purchased from other suppliers.
Four electric cooperative associations, financed by the RUS, operate within Gulf Power's service territory. These cooperatives purchase their full requirements from PowerSouth and SEPA (a federal power marketing agency). A non-affiliated utility also operates within Gulf Power's service territory and purchases its full requirements from Gulf Power.
Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided.
As of December 31, 2017, there were approximately 72 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.
As of December 31, 2017, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Georgia Power and Southern Power through a service agreement. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Georgia Power has entered into substantially similar agreements with Georgia Transmission Corporation, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Southern Power assumed or entered into PPAs with some of the traditional electric operating companies, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" above and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 herein for additional information concerning Southern Power's PPAs.
SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.
Southern Company Gas
Southern Company Gas is engaged in the distribution of natural gas in seven states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2017 are as follows:
|
| | | | | |
Utility | State | Number of customers |
| Approximate miles of pipe |
|
| | (in thousands) | |
Nicor Gas | Illinois | 2,228 |
| 34,300 |
|
Atlanta Gas Light Company | Georgia | 1,622 |
| 33,500 |
|
Virginia Natural Gas | Virginia | 299 |
| 5,600 |
|
Elizabethtown Gas(*) | New Jersey | 292 |
| 3,200 |
|
Florida City Gas | Florida | 109 |
| 3,700 |
|
Chattanooga Gas Company | Tennessee | 66 |
| 1,600 |
|
Elkton Gas(*) | Maryland | 7 |
| 100 |
|
Total | | 4,623 |
| 82,000 |
|
| |
(*) | For information relating to the pending asset sales of Elizabethtown Gas and Elkton Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Merger, Acquisition, and Disposition Activities" of Southern Company Gas in Item 7 herein and Note 11 to the financial statements of Southern Company Gas under "Proposed Sale of Elizabethtown Gas and Elkton Gas" in Item 8 herein. |
For information relating to the sources of revenue for Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.
Competition
Electric
The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992, which allowed IPPs to access a utility's transmission network in order to sell electricity to other utilities.
The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.
The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to the provisions of this Act, all areas within existing municipal limits were assigned to the primary electric supplier therein. Areas outside of such municipal limits were either to be assigned or to be declared open for customer choice of supplier by action of the Georgia PSC pursuant to standards set forth in this Act. Consistent with such standards, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.
Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may extend or maintain its electric
system subject to certain regulatory approvals; extensions of facilities by such utility, or extensions of facilities into that area by other utilities, may not be made except upon a showing of, and a grant of a certificate of, public convenience and necessity. Areas included in such a certificate that are subsequently annexed to municipalities may continue to be served by the holder of the certificate, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.
Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors.
Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales across various U.S. utility markets. The needs of these markets are driven by the demands of end users and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.
As of December 31, 2017, Alabama Power had cogeneration contracts in effect with eight industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2017, Alabama Power purchased approximately 98 million KWHs from such companies at a cost of $3 million.
As of December 31, 2017, Georgia Power had contracts in effect with 27 small power producers whereby Georgia Power purchases their excess generation. During 2017, Georgia Power purchased 1.6 billion KWHs from such companies at a cost of $114 million. Georgia Power also has PPAs for electricity with four cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2017, Georgia Power purchased 26 million KWHs at a cost of $0.7 million from these facilities.
Also during 2017, Georgia Power purchased energy from three customer-owned generating facilities. These customers provide only energy to Georgia Power, make no capacity commitment, and are not dispatched by Georgia Power. During 2017, Georgia Power purchased a total of 317 million KWHs from the three customers at a cost of approximately $25 million.
As of December 31, 2017, Gulf Power had agreements in effect with various industrial, commercial, and qualifying facilities pursuant to which Gulf Power purchases "as available" energy from customer-owned generation. During 2017, Gulf Power purchased 277 million KWHs from such companies for approximately $7 million.
As of December 31, 2017, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2017, Mississippi Power did not purchase any excess generation from this customer.
Natural Gas
Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.
Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.
Customer demand for natural gas could be affected by numerous factors, including:
changes in the availability or price of natural gas and other forms of energy;
general economic conditions;
energy conservation, including state-supported energy efficiency programs;
legislation and regulations;
the cost and capability to convert from natural gas to alternative energy products; and
technological changes resulting in displacement or replacement of natural gas appliances.
The natural gas-related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.
The availability and affordability of natural gas have provided cost advantages and further opportunity for growth of the businesses.
Seasonality
The demand for electric power and natural gas supply is affected by seasonal differences in the weather. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas in the future may fluctuate substantially on a seasonal basis. In addition, Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less power and natural gas when weather conditions are milder.
Regulation
State Commissions
The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Southern Company System" and "Rate Matters" herein for additional information.
Federal Power Act
The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.
Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2017, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,670,000 KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1,087,296 KWs.
In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission also filed petitions for rehearing of the FERC order. In April 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. The order also denied all of the other rehearing requests. In May 2016, Alabama Rivers Alliance and American Rivers filed a second rehearing request and, in June 2016, also filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit for review of the license and the rehearing denial order. The FERC issued an order in September 2016 denying the second rehearing request, and American Rivers and Alabama Rivers Alliance subsequently filed an appeal of that order at the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit consolidated the two appeals into one proceeding.
In 2017, Alabama Power continued the process of developing an application to relicense the Harris Dam project on the Tallapoosa River, which is expected to be filed with the FERC by November 30, 2021. The current Harris Dam project license will expire on November 30, 2023.
In 2017, Georgia Power continued the process of developing an application to relicense the Wallace Dam project on the Oconee River. The current Wallace Dam project license will expire on June 1, 2020. Georgia Power's hydro electric licenses expiring in 2023 include the Lloyd Shoals project, the Riverview project, and the Langdale project. The FERC relicensing proceedings for these three projects are expected to begin in 2018.
Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain Plant, a pure pumped storage facility of 847,800 KW capacity. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.
Licenses for all projects, excluding those discussed above, expire in the years 2023-2066 in the case of Alabama Power's projects and in the years 2035-2044 in the case of Georgia Power's projects.
Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another,
the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.
The ultimate outcome of these matters cannot be determined at this time.
Nuclear Regulation
Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.
The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1 and 2 expire in 2047 and 2049, respectively.
In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for additional information.
See Notes 1 and 9 to the financial statements of Southern Company, Alabama Power, and Georgia Power in Item 8 herein for information on nuclear decommissioning costs and nuclear insurance.
Environmental Laws and Regulations
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. For Southern Company Gas, substantially all of these costs are related to former manufactured gas plants sites, which are primarily recovered through existing ratemaking provisions. See Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 herein for additional information.
Compliance with federal environmental laws and resulting regulations has been, and will continue to be, a significant focus for Southern Company, each traditional electric operating company, Southern Power, SEGCO, and Southern Company Gas. New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein for additional information about environmental issues, including, but not limited to, proposed and final regulations related to air quality, water quality, CCRs, and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 herein for additional information about environmental issues and global climate issues. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 herein for additional information about environmental remediation liabilities.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state-level adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates
could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See "Construction Program" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each of the traditional electric operating companies, Southern Power, and Southern Company Gas in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.
Rate Matters
Rate Structure and Cost Recovery Plans
Electric
The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power, Gulf Power, and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.
The traditional electric operating companies recover certain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved compliance, storm damage, and certain other costs are recovered at Alabama Power, Gulf Power, and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power and Gulf Power through periodic base rate proceedings.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein and Note 3 to the financial statements of Southern Company and each of the traditional electric operating companies under "Retail Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also, see Note 1 to the financial statements of Southern Company and each of the traditional electric operating companies in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and compliance costs through rate mechanisms.
See "Integrated Resource Planning" herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover financing costs for construction of Plant Vogtle Units 3 and 4 during the construction period beginning in 2011.
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Rate Recovery" of Mississippi Power in Item 7 herein for information on cost recovery plans with respect to the Kemper County energy facility.
The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of each of the registrants in Item 7 herein for information on the traditional electric operating companies' and Southern Power Company's market-based rate authority and pending FERC proceedings relating to this authority.
Mississippi Power serves long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of Mississippi Power's operating revenues in 2017 and are largely subject to rolling 10-
year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Natural Gas
Southern Company Gas' seven natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies with respect to rates charged to their customers, maintenance of accounting records, and various service and safety matters. Rates charged to these customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide each natural gas distribution utility the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt, and provide a reasonable return. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
With the exception of Atlanta Gas Light Company, which operates in a deregulated environment in which gas marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas.
The natural gas distribution utilities, excluding Atlanta Gas Light Company, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing natural gas for their customers. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Utility Regulation and Rate Design" of Southern Company Gas in Item 7 herein and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.
Integrated Resource Planning
Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See "Environmental Laws and Regulations" above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies.
Certain of the traditional electric operating companies are required to file IRPs with their respective state PSC as discussed below.
Georgia Power
Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Rate Plans" and " – Integrated Resource Plan" and "Nuclear Construction" and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans," "– Integrated Resource Plan," and "– Nuclear Construction" in Item 8 herein for additional information.
Gulf Power
Annually by April 1, Gulf Power must file a 10-year site plan with the Florida PSC containing Gulf Power's estimate of its power-generating needs in the period and the general location of its proposed power plant sites. The 10-year site plans submitted by the state's electric utilities are reviewed by the Florida PSC and subsequently classified as either "suitable" or "unsuitable." The Florida PSC then reports its findings along with any suggested revisions to the Florida Department of Environmental Protection for its consideration at any subsequent electrical power plant site certification proceedings. Under
Florida law, any 10-year site plans submitted by an electric utility are considered tentative information for planning purposes only and may be amended at any time at the discretion of the utility with written notification to the Florida PSC.
Gulf Power's most recent 10-year site plan was classified by the Florida PSC as "suitable" in November 2017. The plan identifies environmental regulations and potential legislation or regulation that would impose mandatory restrictions on greenhouse gas emissions. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality," "– Environmental Laws and Regulations – Coal Combustion Residuals," and "– Global Climate Issues" of Gulf Power in Item 7 herein.
As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) in March 2016. In August 2016, the Florida PSC approved Gulf Power's request to reclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date, totaling approximately $63 million, to a regulatory asset. Gulf Power began amortizing the investment balances over 15 years effective January 1, 2018 as determined in a rate case settlement agreement approved by the Florida PSC on April 4, 2017.
Mississippi Power
Mississippi Power's 2010 IRP indicated that, among other things, Mississippi Power planned to construct the Kemper County energy facility as an IGCC to meet its identified needs, to add environmental controls at Plant Daniel Units 1 and 2, to defer environmental controls at Plant Watson Units 4 and 5, and to continue operation of the combined cycle Plant Daniel Units 3 and 4. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Air Quality" and "– Global Climate Issues" of Mississippi Power in Item 7 herein.
On February 6, 2018, the Mississippi PSC approved a settlement agreement related to cost recovery for the Kemper County energy facility, pursuant to which Mississippi Power agreed to file a Reserve Margin Plan (RMP) by August 2018. The RMP will include many of the same aspects of a traditional IRP, but the RMP will also contain alternatives proposed by Mississippi Power to address its current capacity which is in excess of Mississippi Power's long-term targeted reserve margin. The ultimate outcome of this matter cannot be determined at this time.
For additional information regarding the Kemper County energy facility, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 herein.
Employee Relations
The Southern Company system had a total of 31,344 employees on its payroll at December 31, 2017.
|
| | |
| Employees at December 31, 2017 |
Alabama Power | 6,613 |
|
Georgia Power | 6,986 |
|
Gulf Power | 1,288 |
|
Mississippi Power | 1,242 |
|
PowerSecure | 1,448 |
|
SCS | 3,740 |
|
Southern Company Gas | 5,318 |
|
Southern Nuclear | 3,936 |
|
Southern Power | 541 |
|
Other | 232 |
|
Total | 31,344 |
|
The traditional electric operating companies and the natural gas distribution utilities have separate agreements with local unions of the IBEW and the Utilities Workers Union of America generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.
Alabama Power has agreements with the IBEW in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2021.
Gulf Power has an agreement with the IBEW covering wages and working conditions, which is in effect through April 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through May 1, 2019. In 2015, Mississippi Power signed a separate agreement with the IBEW related solely to the Kemper County energy facility; that current agreement is in effect through March 15, 2021. In August 2017, Mississippi Power signed an agreement with the IBEW that added several job classifications and provided guidelines related to the reorganization at the Kemper County energy facility.
Southern Nuclear has a five-year agreement with the IBEW covering certain employees at Plants Hatch and Plant Vogtle Units 1 and 2, which is in effect through June 30, 2021. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley is in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.
The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.
The natural gas distribution utilities have separate agreements with local unions of the IBEW and Utilities Workers Union of America covering wages, working conditions, and procedures for handling grievances and arbitration. Nicor Gas' agreement with the IBEW is effective through February 29, 2020. Virginia Natural Gas' agreement with the IBEW is effective through May 16, 2020. Elizabethtown Gas' agreement with the Utility Workers Union of America is effective through November 21, 2019. The agreements also make the terms of the Southern Company Gas pension plan subject to collective bargaining with the unions when significant changes to the benefit accruals are considered by Southern Company Gas.
Effective in December 2017, 538 employees transferred from SCS to Southern Power. Southern Power became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including accumulated other comprehensive income impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, Southern Power's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations.
Item 1A. RISK FACTORS
In addition to the other information in this Form 10-K, includingMANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 ofeach registrant, and other documents filed by Southern Company and/or itssubsidiaries with the SEC from time to time, the following factors should becarefully considered in evaluating Southern Company and its subsidiaries. Suchfactors could affect actual results and cause results to differ materially fromthose expressed in any forward-looking statements made by, or on behalf of, SouthernCompany and/or its subsidiaries.
UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS
Southern Company and its subsidiaries are subject to substantial state and federal governmentalregulation. Compliance with current and future regulatory requirements andprocurement of necessary approvals, permits, and certificates may result insubstantial costs to Southern Company and its subsidiaries.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, are subject to substantial regulation from federal, state, and local regulatory agencies. Southern Company and its subsidiaries are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from the governmental agencies that regulate various aspects of their businesses. Jointly-owned facilities may be subject to regulation by governmental agencies of more than one state and those state's governmental agencies may have different policies with respect to such jointly-owned facilities. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs (including a reasonable return on invested capital) through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. A state PSC or other applicable state regulatory agency, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and by Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments must be approved by the FERC. These wholesale rates could be affected by changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority. The FERC rules related to retaining the authority to sell electricity at market-based rates in the wholesale markets are important for the traditional electric operating companies and Southern Power if they are to remain competitive in the wholesale markets in which they operate.
The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs or otherwise negatively affect their results of operations.
The Southern Company system's costs of compliance with environmental laws are significant. The costs of compliance with current and future environmental laws and the incurrence of environmental liabilities could negatively impact the net income, cash flows, and financial condition of the registrants.
The Southern Company system's operations are subject to extensive regulation by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and the protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. The registrants expect that these expenditures will continue to be significant in the future.
The EPA has adopted and is implementing regulations governing air and water quality, including the emission of nitrogen oxide, sulfur dioxide, fine particulate matter, ozone, mercury, and other air pollutants under the Clean Air Act and regulations governing cooling water intake structures and effluent guidelines for steam electric generating plants under the Clean Water Act. The EPA also is reconsidering regulations governing the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at power generation plants.
Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations affected by historical operations or subject to contractual obligations.
Existing environmental laws and regulations may be revised or new laws and regulations related to air, water, land, and the protection of other natural resources may be adopted or become applicable to the traditional electric operating companies, Southern Power, and/or Southern Company Gas.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, releases of regulated substances, and alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.
The Southern Company system's ultimate environmental compliance strategy, including potential electric generating unit retirement and replacement decisions, and future environmental capital expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered on a timely basis through regulated rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity or natural gas.
Compliance with any new or revised environmental laws or regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The ultimate impact will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may affect their demand for electricity and natural gas.
The Southern Company system may be exposed to regulatory and financial risks related to the impact of greenhouse gas (GHG) legislation and regulation.
In 2015, the EPA published final rules limiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of the litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO2 emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing GHG emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.
Costs associated with these actions could be significant to the utility industry and the Southern Company system. However, the ultimate impact of these environmental laws and regulations will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future GHG constraints may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs. Future GHG constraints focused on minimizing emissions from natural gas, albeit lower than other fossil fuels, could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.
The net income of Southern Company, the traditional electric operating companies, and Southern Power could be negatively impacted by changes in regulations related to transmission planning processes and competition in the wholesale electric markets.
The traditional electric operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority of transmission revenues are collected through retail rates. FERC rules pertaining to regional transmission planning and cost allocation present challenges to transmission planning and the wholesale market structure in the Southeast. The key impacts of these rules include:
possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;
delays and additional processes for developing transmission plans; and
possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.
The FERC rules related to transmission are intended to spur the development of new transmission infrastructure to promote and encourage the integration of renewable sources of supply as well as facilitate competition in the wholesale market by providing more choices to wholesale power customers. Technology changes in the power and fuel industries continue to create significant impacts to wholesale transaction cost structures. The impact of these and other such developments and the effect of changes in levels of wholesale supply and demand are uncertain. The financial condition, net income, and cash flows of Southern Company, the traditional electric operating companies, and Southern Power could be adversely affected by these and other changes.
The traditional electric operating companies and Southern Power could be subject to higher costs as a result of implementing and maintaining compliance with the North American Electric Reliability Corporation mandatory reliability standards along with possible associated penalties for non-compliance.
Owners and operators of bulk power systems, including the traditional electric operating companies, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation and enforced by the FERC. Compliance with or changes in the mandatory reliability standards may subject the traditional electric operating companies and Southern Power to higher operating costs and/or increased capital expenditures. If any traditional electric operating company or Southern Power is found to be in noncompliance with these standards, such traditional electric operating company or Southern Power could be subject to sanctions, including substantial monetary penalties.
Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation, which has and could have a further material impact on the results of operations, financial condition, and cash flows of the registrants.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation significantly changes the U.S. Internal Revenue Code by, among other things, reducing the federal corporate income tax rate to 21% and repealing the corporate alternative minimum tax. As a result of the tax rate reduction, Southern Company recorded net, non-cash federal income tax benefits of $264 million in the fourth quarter 2017, comprised primarily of a $743 million tax benefit resulting from reductions in deferred tax liabilities at Southern Power, partially offset by tax expenses of $372 million and $93 million resulting from reductions in deferred tax assets at Mississippi Power and Southern Company Gas, respectively.
The tax rate reduction also resulted in a $6.9 billion increase in regulatory liabilities and a $0.4 billion decrease in regulatory assets across the traditional electric operating companies and the natural gas distribution utilities. The regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies.
For businesses other than regulated utility businesses, the Tax Reform Legislation allows 100% bonus depreciation of qualified property through 2022, which phases down through 2027, and limits interest expense deductions. Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. The Tax Reform Legislation retains normalization provisions for public utility property and existing renewable energy incentives. However, the tax rate reduction delays the utilization of renewable tax credit carryforwards as described in Note 5 to the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Power under "Federal Tax Reform Legislation" in Item 8 herein.
The Tax Reform Legislation also includes provisions that limit the utilization of future net operating losses and limit the deductibility of certain executive compensation and other expenses. Further, while it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as funds from operations to debt percentage, used by the credit rating agencies to assess the registrants, Southern Company Gas Capital, and Nicor Gas may be negatively impacted.
The Tax Reform Legislation is unclear in certain respects and will require interpretations, guidance, and implementing regulations by the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. Southern Company and its subsidiaries are continuing to review the Tax Reform Legislation and are assessing whether any potential actions are available to mitigate adverse impacts of the legislation. Southern Company and its subsidiaries may identify additional impacts as they further assess the Tax Reform Legislation and as the IRS issues interpretations and implements regulations. Southern Company will continue to monitor the actions of state legislatures and state taxing authorities to see how the states may adopt and implement the Tax Reform Legislation. While the ultimate impact of the Tax Reform Legislation, future interpretations and implementation of regulations by the IRS and state tax authorities, and any mitigating actions Southern Company and its subsidiaries may take cannot be determined at this time, the Tax Reform Legislation had and could have a further material impact on the results of operations, financial condition and cash flows of the registrants.
OPERATIONAL RISKS
The financial performance of Southern Company and its subsidiaries may be adverselyaffected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.
The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions. There are many risks that could affect these operations and performance of corporate functions, including:
operator error or failure of equipment or processes;
accidents or explosions;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
terrorist attacks (physical and/or cyber);
fuel or material supply interruptions;
transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities;
compliance with mandatory reliability standards, including mandatory cyber security standards;
implementation of new technologies;
information technology system failure;
cyber intrusion;
an environmental event, such as a spill or release; and
catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, tornadoes, and storms, pandemic health events such as influenzas, or other similar occurrences.
A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or natural gas distribution or storage facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected traditional electric operating company, Southern Power, or Southern Company Gas and of Southern Company.
Operation of nuclear facilities involves inherent risks, including environmental,safety, health, regulatory, natural disasters, terrorism, and financial risks, that could result in fines or theclosure of the nuclear units owned by Alabama Power or Georgia Powerand which may present potential exposures in excess of insurance coverage.
Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represent approximately 3,680 MWs, or 8% of the Southern Company system's electric generation capacity as of December 31, 2017. In addition, these units generated approximately 25% of the total KWHs generated by each of Alabama Power and Georgia Power in the year ended December 31, 2017. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction of Plant Vogtle Units 3 and 4. Due solely to the increase in nuclear generating capacity, the below risks are expected to increase incrementally once Plant Vogtle Units 3 and 4 are operational. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as:
the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;
uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;
potential liabilities arising out of the operation of these facilities;
significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;
the threat of a possible terrorist attack, including a potential cyber security attack; and
the potential impact of an accident or natural disaster.
It is possible that damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future safety requirements promulgated by the NRC could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a serious nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units or require additional safety measures at new and existing units. Moreover, a major incident at any nuclear facility in the U.S., including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.
In addition, potential terrorist threats could result in increased nuclear licensing or compliance costs that are difficult to predict.
Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs.
Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these regulatory requirements could result in substantial monetary penalties or potential early retirement of storage facilities, which could trigger an associated impairment. The occurrence of any of these events not fully covered by insurance or otherwise could adversely affect Southern Company Gas' and Southern Company's financial condition and results of operations.
Physical attacks, both threatened and actual, could impact the ability of the traditional electric operating companies, Southern Power, and Southern Company Gas to operate and could adversely affect financial results and liquidity.
The traditional electric operating companies, Southern Power, and Southern Company Gas face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical attacks against key suppliers or service providers could have a similar effect on Southern Company and its subsidiaries.
Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical attacks. If assets were to fail, be physically damaged, or be breached and were not recovered in a timely way, the traditional electric operating companies, Southern Power, or Southern Company Gas, as applicable, may be unable to fulfill critical business functions. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or physical security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
These events could harm the reputation of and negatively affect the financial results of the registrants through lost revenues and costs to repair damage, if such costs cannot be recovered.
An information security incident, including a cybersecurity breach, or the failure of one or more key information technology systems, networks, or processes could impact the ability of the registrants to operate and could adversely affect financial results and liquidity.
Information security risks have generally increased in recent years as a result of the proliferation of new technology and increased sophistication and frequency of cyber attacks and data security breaches. The traditional electric operating
companies, Southern Power, and Southern Company Gas operate in highly regulated industries that require the continued operation of sophisticated information technology systems and network infrastructure, which are part of interconnected distribution systems. Because of the critical nature of the infrastructure, increased connectivity to the internet, and technology systems' inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, or other types of data security breaches, Southern Company and its subsidiaries face a heightened risk of cyberattack. Parties that wish to disrupt the U.S. bulk power system or Southern Company system operations could view these computer systems, software, or networks as targets. The registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their information technology systems and confidential data or to attempts to disrupt utility operations. As a result, Southern Company and its subsidiaries face on-going threats to their assets, including assets deemed critical infrastructure, where databases and systems have been, and will likely continue to be, subject to advanced computer viruses or other malicious codes, unauthorized access attempts, phishing, and other cyber attacks. While there has been no material impact on business or operations from these attacks, the registrants cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure.
In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third party service providers that could also be targets of cyber attacks. Generally, Southern Company and its subsidiaries enter certain contractual security guarantees and assurances with these third parties to help ensure the security and safety of this information.
Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external cyber attacks. If assets were to fail or be breached and were not recovered in a timely way, the affected registrant may be unable to fulfill critical business functions, and sensitive and other data could be compromised. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected registrant to penalties and claims from regulators or other third parties. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.
These events could negatively affect the financial results of the registrants through lost revenues, costs to recover and repair damage, and costs associated with governmental actions in response to such attacks, litigation, and reputational damage if such costs cannot be recovered through insurance or otherwise.
The Southern Company system may not be able to obtainadequate natural gas and other fuel supplies required to operate the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.
The traditional electric operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, as applicable, from a number of suppliers. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs and potentially reduce the net income of the affected traditional electric operating company or Southern Power and Southern Company.
Southern Company Gas' primary business is the distribution and sale of natural gas through its regulated and unregulated subsidiaries. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane or a pipeline failure. Southern Company Gas also relies on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to Southern Company Gas' distribution systems. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Disruption in natural gas supplies could limit the ability to fulfill these contractual obligations.
The traditional electric operating companies and Southern Power have become more dependent on natural gas for a portion of their electric generating capacity. In many instances, the cost of purchased power expense was $645 million,for the traditional electric operating companies and Southern Power is influenced by natural gas prices. Historically, natural gas prices have been more volatile than prices of other fuels. In recent years, domestic natural gas prices have been depressed by robust supplies, including production from shale gas. These market conditions, together with additional regulation of coal-fired generating units, have increased the traditional electric operating companies' reliance on natural gas-fired generating units.
The traditional electric operating companies are also dependent on coal for a decreaseportion of $27 million,their electric generating capacity. The traditional electric operating companies depend on coal supply contracts, and the counterparties to these agreements may not fulfill their obligations to supply coal to the traditional electric operating companies. The suppliers may experience financial or 4.0%
technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers may not be required to supply coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their coal requirements under these contracts, they may be required to purchase their coal requirements at higher prices, which may not be recoverable through rates.
The revenues of Southern Company, the traditional electric operating companies, and SouthernPower depend inpart on sales under PPAs. The failure of a counterparty to one of these PPAs toperform its obligations, the failure of the traditional electric operating companies or Southern Power to satisfy minimum requirements under the PPAs, or the failure to renew the PPAs or successfully remarket the related generating capacity could have a negativeimpact on the net income and cash flows of the affected traditional electric operating companyor Southern Power and of Southern Company.
Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power's top three customers, Georgia Power, Duke Energy Corporation, and Morgan Stanley Capital Group accounted for 11.3%, 6.7%, and 4.5%, respectively, of Southern Power's total revenues for the year ended December 31, 2017. In addition, the traditional electric operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. The failure of one of the purchasers to perform its obligations could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.
Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. The failure of the traditional electric operating companies or Southern Power to satisfy minimum operational or availability requirements under these PPAs could result in payment of damages or termination of the PPAs.
The asset management arrangements between Southern Company Gas' wholesale gas services and its customers, including the natural gas distribution utilities, may not be renewed or may be renewed at lower levels, which could have a significant impact on Southern Company Gas' financial results.
Southern Company Gas' wholesale gas services currently manages the storage and transportation assets of the natural gas distribution utilities except Nicor Gas. The profits earned from the management of these affiliate assets are shared with the respective affiliate's customers (and for Atlanta Gas Light Company with the Georgia PSC's Universal Service Fund), except for Chattanooga Gas Company and Elkton Gas where wholesale gas services are provided under annual fixed-fee agreements. These asset management agreements are subject to regulatory approval and such agreements may not be renewed or may be renewed with less favorable terms.
Southern Company Gas' wholesale gas services also has asset management agreements with certain non-affiliated customers and its financial results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.
Increased competition could negatively impact Southern Company's and its subsidiaries' revenues, results of operations, and financial condition.
The Southern Company system faces increasing competition from other companies that supply energy or generation and storage technologies. Changes in technology may make the Southern Company system's electric generating facilities owned by the traditional electric operating companies and Southern Power less competitive. Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas also faces competition in its unregulated markets.
A key element of the business models of the traditional electric operating companies and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation and storage technologies that produce and store power, including fuel cells, microturbines, wind turbines, solar cells, and batteries. Advances in technology or changes in laws or regulations could reduce the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology.
It is also possible that rapid advances in central station power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power, which could reduce the revenues or increase the expenses of Southern Company, the traditional electric operating companies, or Southern Power.
Southern Company Gas' gas marketing services is affected by competition from other energy marketers providing similar services in Southern Company Gas' service territories, most notably in Illinois and Georgia. Southern Company Gas' wholesale gas services competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines based on the ability to aggregate competitively-priced commodities with transportation and storage capacity. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region.
If new technologies become cost competitive and achieve sufficient scale, the market share of the traditional electric operating companies, Southern Power, and Southern Company Gas could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets. If state PSCs or other applicable state regulatory agencies fail to adjust rates to reflect the impact of any changes in loads, increasing self-generation, and the growth of distributed generation, the financial condition, results of operations, and cash flows of Southern Company and the affected traditional electric operating company or Southern Company Gas could be materially adversely affected.
Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company's and its subsidiaries' results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with major construction projects and ongoing operations. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses. If Southern Company and its subsidiaries are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
CONSTRUCTION RISKS
The registrants may incuradditional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities ofthe traditional electric operating companies, Southern Power, and Southern Company Gas requireongoing capital expenditures, including those to meet environmental standards.
General
The businesses of the registrants require substantial capital expenditures for investments in new facilities and, for the traditional electric operating companies, capital improvements to transmission, distribution, and generation facilities, and, for Southern Company Gas, capital improvements to natural gas distribution and storage facilities, including those to meet environmental standards. Certain of the traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company Gas is replacing certain pipelines in its natural gas distribution system and is involved in two new gas pipeline construction projects. The Southern Company system intends to continue its strategy of developing and constructing other new facilities, expanding or updating existing facilities, and adding environmental control equipment. These types of projects are long term in nature and in some cases include the development and construction of facilities with designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:
shortages and inconsistent quality of equipment, materials, and labor;
changes in labor costs and productivity;
work stoppages;
contractor or supplier delay or non-performance under construction, operating, or other agreements or non-performance by other major participants in construction projects;
delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;
delays associated with start-up activities, including major equipment failure and system integration, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC or other applicable state regulatory agency);
operational readiness, including specialized operator training and required site safety programs;
impacts of new and existing laws and regulations, including environmental laws and regulations;
the outcome of legal challenges to projects, including legal challenges to regulatory approvals;
failure to construct in accordance with permitting and licensing requirements;
failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;
continued public and policymaker support for such projects;
adverse weather conditions or natural disasters;
other unforeseen engineering or design problems;
changes in project design or scope;
environmental and geological conditions;
delays or increased costs to interconnect facilities to transmission grids; and
unanticipated cost increases, including materials and labor, and increased financing costs as a result of changes in market interest rates or as a result of construction schedule delays.
If a traditional electric operating company, Southern Power, or Southern Company Gas is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts. Additionally, each Southern Company Gas pipeline construction project involves separate joint venture participants, Southern Power participates in partnership agreements with respect to renewable energy projects, and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction.
Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and may not be recoverable through regulated rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of the affected registrant.
Construction delays could result in the loss of otherwise available investment tax credits, PTCs, and other tax incentives. Furthermore, if construction projects are not completed according to specification, a traditional electric operating company, Southern Power, or Southern Company Gas and Southern Company may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income.
Once facilities become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to maintain efficiency, to comply with changing environmental requirements, or to provide safe and reliable operations.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4.
Plant Vogtle Units 3 and 4 construction and rate recovery
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under a substantially fixed price engineering, procurement, and construction agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the EPC Contractor to allow construction to continue (Interim Assessment Agreement). The Interim Assessment Agreement expired on July 27, 2017 upon the effectiveness of a services agreement between the Vogtle Owners and the EPC Contractor for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear (Vogtle Services Agreement). In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth Vogtle Construction Monitoring (VCM) report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel Power Corporation (Bechtel) serving as the primary construction contractor. Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The construction completion agreement between Georgia Power, for itself and as agent for the other Vogtle Owners, and Bechtel (Bechtel Agreement) is a cost reimbursable plus
fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the original engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 (Contractor Settlement Agreement) was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined below) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the return on equity (ROE) used to calculate the Nuclear Construction Cost Recovery (NCCR) tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 Alternative Rate Plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for allowance for funds used during construction equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the settlement agreement approved by the Georgia PSC on December 20, 2016. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding Toshiba's guarantee of certain obligations of the EPC Contractor (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's construction work in progress balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time.
See Note 3 to the financial statements of Southern Company under "Nuclear Construction" and of Georgia Power under "Retail Regulatory Matters - Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Southern Company Gas' significant investments in pipelines and pipeline development projects involve financial and execution risks.
Southern Company Gas has made significant investments in existing pipelines and pipeline development projects. Many of the existing pipelines are, and when completed many of the pipeline development projects will be, operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of the investment. In addition, from time to time, Southern Company Gas may be required to contribute additional capital to a pipeline joint venture or guarantee the obligations of such joint venture.
With respect to certain pipeline development projects, Southern Company Gas will rely on its joint venture partners for construction management and will not exercise direct control over the process. All of the pipeline development projects are dependent on contractors for the successful and timely completion of the projects. Further, the development of pipeline projects involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require the expenditure of significant amounts of capital. These projects may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' capital expenditures to exceed its initial expectations. Moreover, Southern Company Gas' revenues will not increase immediately upon the expenditure of funds on a pipeline project. Pipeline construction occurs over an extended period of time and Southern Company Gas will not receive material increases in revenues until the project is placed in service.
The occurrence of any of the foregoing events could adversely affect the results of operations, cash flows, and financial condition of Southern Company Gas and Southern Company.
FINANCIAL, ECONOMIC, AND MARKET RISKS
The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to risks, many of which are beyondtheir control, including changes in energy prices and fuel costs, which may reduce revenues and increase costs.
The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Among the factors that could influence energy prices and fuel costs are:
prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;
demand for energy and the extent of additional supplies of energy available from current or new competitors;
liquidity in the general wholesale electricity and natural gas markets;
weather conditions impacting demand for electricity and natural gas;
seasonality;
transmission or transportation constraints, disruptions, or inefficiencies;
availability of competitively priced alternative energy sources;
forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;
the financial condition of market participants;
the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels, including natural gas;
natural disasters, wars, embargos, acts of terrorism, and other catastrophic events; and
federal, state, and foreign energy and environmental regulation and legislation.
Certain of these factors could increase the expenses of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such increases may not be fully recoverable through rates. Other of these factors could reduce the revenues of the traditional electric operating companies, Southern Power, or Southern Company Gas and Southern Company.
Historically, the traditional electric operating companies and Southern Company Gas from time to time have experienced underrecovered fuel and/or purchased gas cost balances and may experience such balances in the future. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through cost recovery clauses, recovery may be denied if costs are deemed to be imprudently incurred, and delays in the authorization of such recovery could negatively impact the cash flows of the affected traditional electric operating company or Southern Company Gas and Southern Company.
The registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the traditional electric operating companies, Southern Power, and Southern Company Gas.
The consumption and use of energy are fundamentally linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. Any economic downturn could negatively impact customer growth and usage per customer, thus reducing the sales of energy and revenues. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the traditional electric operating companies, Southern Power, and Southern Company Gas.
Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy.
Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and Southern Company Gas have PSC or other applicable state regulatory agency mandates to promote energy efficiency. Conservation programs could impact the financial results of the registrants in different ways. For example, if any traditional electric operating company or Southern Company Gas is required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional electric operating company or Southern Company Gas and Southern Company. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.
In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, new electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. The Southern Company system uses best available methods and experience to incorporate the effects of changes in customer behavior, state and federal programs, PSC or other applicable state regulatory agency mandates, and technology, but the Southern Company system's planning processes may not appropriately estimate and incorporate these effects.
All of the factors discussed above could adversely affect Southern Company's, the traditional electric operating companies', Southern Power's, and/or Southern Company Gas' results of operations, financial condition, and liquidity.
The operating results of the registrants are affected by weather conditions and may fluctuate on a seasonal andquarterly basis. In addition, catastrophic events, such as fires, earthquakes, hurricanes, tornadoes, floods, droughts, and storms, could result in substantial damage to or limit the operation of the properties of the traditional electric operating companies, Southern Power, and/or Southern Company Gas and could negatively impact results of operation, financial condition, and liquidity.
Electric power and natural gas supply are generally seasonal businesses. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. In most of the areas the traditional electric operating companies serve, electric power sales peak during the summer with a smaller peak during the winter, while in most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the registrants may fluctuate substantially on a seasonal basis. In addition, the traditional electric operating companies, Southern Power, and Southern Company Gas have historically sold less
power and natural gas when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, and available cash of the affected registrant.
Further, volatile or significant weather events could result in substantial damage to the transmission and distribution lines of the traditional electric operating companies, the generating facilities of the traditional electric operating companies and Southern Power, and the natural gas distribution and storage facilities of Southern Company Gas. The traditional electric operating companies, Southern Power, and Southern Company Gas have significant investments in the Atlantic and Gulf Coast regions and Southern Power has wind and natural gas investments in various states which could be subject to severe weather, as well as solar investments in various states which could be subject to natural disasters. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.
In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. Historically, the traditional electric operating companies from time to time have experienced deficits in their storm cost recovery reserve balances and may experience such deficits in the future. Any denial by the applicable state PSC or other applicable state regulatory agency or delay in recovery of any portion of such costs could have a material negative impact on a traditional electric operating company's or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.
In addition, damages resulting from significant weather events within the service territory of any traditional electric operating company or Southern Company Gas or affecting Southern Power's customers may result in the loss of customers and reduced demand for energy for extended periods. Any significant loss of customers or reduction in demand for energy could have a material negative impact on a traditional electric operating company's, Southern Power's, or Southern Company Gas' and Southern Company's results of operations, financial condition, and liquidity.
Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
Southern Company and its subsidiaries have made significant acquisitions and investments in the past and may in the future make additional acquisitions, dispositions, or other strategic ventures or investments, including the proposed sale by Pivotal Utility Holdings, a wholly-owned subsidiary of Southern Company Gas, of the assets of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, and the potential sale by Southern Power of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers.
Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk. These transactions may also affect the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.
These transactions also involve risks, including:
they may not result in an increase in income or provide an adequate return on capital or other anticipated benefits;
they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;
they may not be successfully integrated into the acquiring company's operations and/or internal control processes;
the due diligence conducted prior year.to a transaction may not uncover situations that could result in financial or legal exposure or the acquiring company may not appropriately evaluate the likelihood or quantify the exposure from identified risks;
they may result in decreased earnings, revenues, or cash flow;
expected benefits of a transaction may be dependent on the cooperation or performance of a counterparty; or
for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through rates may not be recoverable.
Southern Company and Southern Company Gas are holding companies and are dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations, including making interest and principal payments on outstanding indebtedness and, for Southern Company, to pay dividends on its common stock.
Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' respective consolidated assets are held by subsidiaries. A significant portion of Southern Company Gas' debt is issued by its 100%-owned subsidiary, Southern Company Gas Capital, and is fully and unconditionally guaranteed by Southern Company Gas. Southern Company's and Southern Company Gas' ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is primarily dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company or Southern Company Gas, the respective subsidiaries have regulatory restrictions and financial obligations that must be satisfied, including among others, debt service and preferred stock dividends. These subsidiaries are separate legal entities and have no obligation to provide Southern Company or Southern Company Gas with funds. In addition, Southern Company and Southern Company Gas may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.
A downgrade in the credit ratings of any of the registrants, Southern Company Gas Capital, or Nicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require posting of collateral or replacing certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for the registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. The registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any registrant, Southern Company Gas Capital, or Nicor Gas, borrowing costs likely would increase, including automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, wasand, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used, and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.
Uncertainty in demand for energy can result in lower earnings or higher costs. If demand for energy falls short of expectations, it could result in potentially stranded assets. If demand for energy exceeds expectations, it could result in increased costs forpurchasing capacity in the open market or building additional electric generation and transmissionfacilities or natural gas distribution and storage facilities.
Southern Company, the traditional electric operating companies, and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. Southern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines and storage facilities, replacing existing pipelines, rewatering storage facilities, and entering new markets and/or expanding in existing markets. These planning processes must look many years into the future in order to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution and storage facilities. Inherent risk exists in predicting demand this far into the future as these future loads are dependent on many uncertain factors, including economic conditions, customer usage patterns, efficiency programs, and customer technology adoption. Because regulators may not permit the traditional electric operating companies or Southern Company Gas' regulated operating companies to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, Southern Company and its subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs and the recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend existing PPAs or find new buyers for existing generation assets as existing PPAs expire, or they may be forced to market these assets at prices lower than originally intended. These situations could have negative impacts on net income and cash flows for the affected registrant.
The traditional electric operating companies are currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-
term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies purchase capacity on the open market or build additional generation and transmission facilities, and for Southern Power to purchase energy or capacity on the open market. Because regulators may not permit the traditional electric operating companies to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power may not be able to recover all of these costs. These situations could have negative impacts on net income and cash flows for the affected registrant.
The businesses of the registrants and Nicor Gas are dependent on their ability to successfully access funds through capital markets and financial institutions. Theinability of any of the registrants or Nicor Gas to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows.
The registrants and Nicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If any of the registrants or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the registrants and Nicor Gas rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of the registrants and Nicor Gas believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain events or market disruptions may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:
an economic downturn or uncertainty;
bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;
capital markets volatility and disruption, either nationally or internationally;
changes in tax policy;
volatility in market prices for electricity and natural gas;
terrorist attacks or threatened attacks on the Southern Company system's facilities or unrelated energy companies' facilities;
war or threat of war; or
the overall health of the utility and financial institution industries.
As of December 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $911 million primarily due to a 14.3% decrease$900 million unsecured term loan that matures on March 31, 2018. Mississippi Power expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. Mississippi Power has been informed by Southern Company that in the averageevent sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity to fund the remaining indebtedness to mature and other cash needs over the next 12 months.
Georgia Power's ability to make future borrowings through its term loan credit facility with the Federal Financing Bank is subject to the satisfaction of customary conditions, as well as certification of compliance with the requirements of the loan guarantee program under Title XVII of the Energy Policy Act of 2005, including accuracy of project-related representations and warranties, delivery of updated project-related information and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Prior to obtaining any further advances under Georgia Power's loan guarantee agreement with the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement.
Failure to comply with debt covenants or conditions could adversely affect the ability of the registrants, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.
The debt and credit agreements of the registrants, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements, which would negatively affect the applicable company's financial condition and liquidity.
Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the costs of nuclear decommissioning.
The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, future government regulation, changes in life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission Alabama Power's and Georgia Power's nuclear plants. The rate of return on assets held in those trusts can significantly impact both the costs of decommissioning and the funding requirements for the trusts.
The registrants are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The financial condition of some insurance companies, the threat of terrorism, and natural disasters, among other things, could have disruptive effects on insurance markets. The availability of insurance covering risks that the registrants and their respective competitors typically insure against may decrease, and the insurance that the registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.
Any losses not covered by insurance, or any increases in the cost per KWH purchased primarilyof applicable insurance, could adversely affect the results of operations, cash flows, or financial condition of the affected registrant.
The use of derivative contracts by Southern Company and its subsidiaries in thenormal course of business could result in financial losses that negatively impact thenet income of the registrants or in reported net income volatility.
Southern Company and its subsidiaries, including the traditional electric operating companies, Southern Power, and Southern Company Gas, use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage foreign currency exchange rate exposure and engage in limited trading activities. The registrants could recognize financial losses as a result of lower naturalvolatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, Southern Company Gas utilizes derivative instruments to lock in economic value in wholesale gas prices, partially offset byservices, which may not qualify or are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income of Southern Company and Southern Company Gas while the positions are open due to mark-to-market accounting.
Future impairments of goodwill or long-lived assets could have a 5.3%material adverse effect on the registrants' results of operations.
Goodwill is assessed for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or circumstances indicate that an asset's carrying amount may not be recoverable. In connection with the completion of the Merger, the application of the acquisition method of accounting was pushed down to Southern Company Gas. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities was recorded as goodwill. This resulted in a significant increase in the volume of KWHs purchased.goodwill recorded on Southern Company's and Southern Company Gas' consolidated balance sheets. At December 31, 2017, goodwill was $6.3 billion and $6.0 billion for Southern Company and Southern Company Gas, respectively.
In 2014,addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the value of goodwill or long-lived assets become impaired, the affected registrant may be required to incur impairment charges that could have a material impact on their results of operations. For example, a wholly-owned subsidiary of Southern Company
Gas owns and operates a natural gas storage facility consisting of two salt dome caverns where recent seismic mapping indicates that proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. In addition, a subsidiary of Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. With respect to Southern Company's subsidiary's investments in leveraged leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.
| |
Item 1B. | UNRESOLVED STAFF COMMENTS. |
None.
Item 2. PROPERTIES
Electric
Electric Properties
The traditional electric operating companies, Southern Power, and SEGCO, at December 31, 2017, owned and/or operated 33 hydroelectric generating stations, 29 fossil fuel generating stations, three nuclear generating stations, 15 combined cycle/cogeneration stations, 35 solar facilities, eight wind facilities, one biomass facility, and one landfill gas facility. The amounts of capacity for each company, as of December 31, 2017, are shown in the table below.
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
| | (KWs) |
| |
FOSSIL STEAM | | | |
Gadsden | Gadsden, AL | 120,000 |
| |
Gorgas | Jasper, AL | 1,021,250 |
| |
Barry | Mobile, AL | 1,300,000 |
| |
Greene County | Demopolis, AL | 300,000 |
| (2 | ) |
Gaston Unit 5 | Wilsonville, AL | 880,000 |
| |
Miller | Birmingham, AL | 2,532,288 |
| (3 | ) |
Alabama Power Total | | 6,153,538 |
| |
Bowen | Cartersville, GA | 3,160,000 |
| |
Hammond | Rome, GA | 800,000 |
| |
McIntosh | Effingham County, GA | 163,117 |
| |
Scherer | Macon, GA | 750,924 |
| (4 | ) |
Wansley | Carrollton, GA | 925,550 |
| (5 | ) |
Yates | Newnan, GA | 700,000 |
| |
Georgia Power Total | | 6,499,591 |
| |
Crist | Pensacola, FL | 970,000 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (6 | ) |
Scherer Unit 3 | Macon, GA | 204,500 |
| (4 | ) |
Gulf Power Total | | 1,674,500 |
| |
Daniel | Pascagoula, MS | 500,000 |
| (6 | ) |
Greene County | Demopolis, AL | 200,000 |
| (2 | ) |
Watson | Gulfport, MS | 862,000 |
| |
Mississippi Power Total | | 1,562,000 |
| |
Gaston Units 1-4 | Wilsonville, AL | | |
SEGCO Total | | 1,000,000 |
| (7 | ) |
Total Fossil Steam | | 16,889,629 |
| |
NUCLEAR STEAM | | | |
Farley | Dothan, AL | | |
Alabama Power Total | | 1,720,000 |
| |
Hatch | Baxley, GA | 899,612 |
| (8 | ) |
Vogtle Units 1 and 2 | Augusta, GA | 1,060,240 |
| (9 | ) |
Georgia Power Total | | 1,959,852 |
| |
Total Nuclear Steam | | 3,679,852 |
| |
COMBUSTION TURBINES | | | |
Greene County | Demopolis, AL | | |
Alabama Power Total | | 720,000 |
| |
Boulevard | Savannah, GA | 19,700 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
McDonough Unit 3 | Atlanta, GA | 78,800 |
| |
McIntosh Units 1 through 8 | Effingham County, GA | 640,000 |
| |
McManus | Brunswick, GA | 481,700 |
| |
Robins | Warner Robins, GA | 158,400 |
| |
Wansley | Carrollton, GA | 26,322 |
| (5 | ) |
Wilson | Augusta, GA | 354,100 |
| |
Georgia Power Total | | 1,759,022 |
| |
Lansing Smith Unit A | Southport, FL | 39,400 |
| |
Pea Ridge Units 1 through 3 | Pea Ridge, FL | 15,000 |
| |
Gulf Power Total | | 54,400 |
| |
Chevron Cogenerating Station | Pascagoula, MS | 147,292 |
| (10 | ) |
Sweatt | Meridian, MS | 39,400 |
| |
Watson | Gulfport, MS | 39,360 |
| |
Mississippi Power Total | | 226,052 |
| |
Addison | Thomaston, GA | 668,800 |
| |
Cleveland County | Cleveland County, NC | 720,000 |
| |
Dahlberg | Jackson County, GA | 756,000 |
| |
Oleander | Cocoa, FL | 791,301 |
| |
Rowan | Salisbury, NC | 455,250 |
| |
Southern Power Total | | 3,391,351 |
| |
Gaston (SEGCO) | Wilsonville, AL | 19,680 |
| (7 | ) |
Total Combustion Turbines | | 6,170,505 |
| |
COGENERATION | | | |
Washington County | Washington County, AL | 123,428 |
| |
Lowndes County | Burkeville, AL | 104,800 |
| |
Theodore | Theodore, AL | 236,418 |
| |
Alabama Power Total | | 464,646 |
| |
COMBINED CYCLE | | | |
Barry | Mobile, AL | | |
Alabama Power Total | | 1,070,424 |
| |
McIntosh Units 10&11 | Effingham County, GA | 1,318,920 |
| |
McDonough-Atkinson Units 4 through 6 | Atlanta, GA | 2,520,000 |
| |
Georgia Power Total | | 3,838,920 |
| |
Lansing Smith Unit 3 | Southport, FL | | |
Gulf Power Total | | 545,500 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
Daniel | Pascagoula, MS | 1,070,424 |
| |
Kemper County/Ratcliffe | Kemper County, MS | 769,898 |
| (11) |
|
Mississippi Power Total | | 1,840,322 |
| |
Franklin | Smiths, AL | 1,857,820 |
| |
Harris | Autaugaville, AL | 1,318,920 |
| |
Mankato | Mankato, MN | 375,000 |
| |
Rowan | Salisbury, NC | 530,550 |
| |
Stanton Unit A | Orlando, FL | 428,649 |
| (12 | ) |
Wansley | Carrollton, GA | 1,073,000 |
| |
Southern Power Total | | 5,583,939 |
| |
Total Combined Cycle | | 12,879,105 |
| |
HYDROELECTRIC FACILITIES | | | |
Bankhead | Holt, AL | 53,985 |
| |
Bouldin | Wetumpka, AL | 225,000 |
| |
Harris | Wedowee, AL | 132,000 |
| |
Henry | Ohatchee, AL | 72,900 |
| |
Holt | Holt, AL | 46,944 |
| |
Jordan | Wetumpka, AL | 100,000 |
| |
Lay | Clanton, AL | 177,000 |
| |
Lewis Smith | Jasper, AL | 157,500 |
| |
Logan Martin | Vincent, AL | 135,000 |
| |
Martin | Dadeville, AL | 182,000 |
| |
Mitchell | Verbena, AL | 170,000 |
| |
Thurlow | Tallassee, AL | 81,000 |
| |
Weiss | Leesburg, AL | 87,750 |
| |
Yates | Tallassee, AL | 47,000 |
| |
Alabama Power Total | | 1,668,079 |
| |
Bartletts Ferry | Columbus, GA | 173,000 |
| |
Goat Rock | Columbus, GA | 38,600 |
| |
Lloyd Shoals | Jackson, GA | 14,400 |
| |
Morgan Falls | Atlanta, GA | 16,800 |
| |
North Highlands | Columbus, GA | 29,600 |
| |
Oliver Dam | Columbus, GA | 60,000 |
| |
Rocky Mountain | Rome, GA | 215,256 |
| (13 | ) |
Sinclair Dam | Milledgeville, GA | 45,000 |
| |
Tallulah Falls | Clayton, GA | 72,000 |
| |
Terrora | Clayton, GA | 16,000 |
| |
Tugalo | Clayton, GA | 45,000 |
| |
Wallace Dam | Eatonton, GA | 321,300 |
| |
Yonah | Toccoa, GA | 22,500 |
| |
6 Other Plants | Various Georgia locations | 18,080 |
| |
Georgia Power Total | | 1,087,536 |
| |
Total Hydroelectric Facilities | | 2,755,615 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
RENEWABLE SOURCES: | | | |
SOLAR FACILITIES | | | |
Fort Benning | Columbus, GA | 30,000 |
| |
Fort Gordon | Augusta, GA | 30,000 |
| |
Fort Stewart | Fort Stewart, GA | 30,000 |
| |
Kings Bay | Camden County, GA | 30,000 |
| |
Dalton | Dalton, GA | 6,012 |
| |
3 Other Plants | Various Georgia locations | 2,984 |
| |
Georgia Power Total | | 128,996 |
| |
Adobe | Kern County, CA | 20,000 |
| |
Apex | North Las Vegas, NV | 20,000 |
| |
Boulder I | Clark County, NV | 100,000 |
| (14 | ) |
Butler | Taylor County, GA | 103,700 |
| |
Butler Solar Farm | Taylor County, GA | 22,000 |
| |
Calipatria | Imperial County, CA | 20,000 |
| |
Campo Verde | Imperial County, CA | 147,420 |
| |
Cimarron | Springer, NM | 30,640 |
| |
Decatur County | Decatur County, GA | 20,000 |
| |
Decatur Parkway | Decatur County, GA | 84,000 |
| |
Desert Stateline | San Bernadino County, CA | 299,900 |
| (14 | ) |
East Pecos | Pecos County, TX | 120,000 |
| |
Garland | Kern County, CA | 205,130 |
| (14 | ) |
Granville | Oxford, NC | 2,500 |
| |
Henrietta | Kings County, CA | 102,000 |
| (14 | ) |
Imperial Valley | Imperial County, CA | 163,200 |
| (14 | ) |
Lamesa | Dawson County, TX | 102,000 |
| |
Lost Hills - Blackwell | Kern County, CA | 33,440 |
| (14 | ) |
Macho Springs | Luna County, NM | 55,000 |
| |
Morelos del Sol | Kern County, CA | 15,000 |
| |
North Star | Fresno County, CA | 61,600 |
| (14 | ) |
Pawpaw | Taylor County, GA | 30,480 |
| |
Roserock | Pecos County, TX | 160,000 |
| (14 | ) |
Rutherford | Rutherford County, NC | 74,800 |
| |
Sandhills | Taylor County, GA | 146,890 |
| |
Spectrum | Clark County, NV | 30,240 |
| |
Tranquillity | Fresno County, CA | 205,300 |
| (14 | ) |
Southern Power Total | | 2,375,240 |
| (15 | ) |
Total Solar | | 2,504,236 |
| |
|
| | | | | |
Generating Station | Location | Nameplate Capacity (1) |
| |
WIND FACILITIES | | | |
Bethel | Castro County, TX | 276,000 |
| |
Grant Plains | Grant County, OK | 147,200 |
| |
Grant Wind | Grant County, OK | 151,800 |
| |
Kay Wind | Kay County, OK | 299,000 |
| |
Passadumkeag | Penobscot County, ME | 42,900 |
| |
Salt Fork | Donley & Gray Counties TX | 174,000 |
| |
Tyler Bluff | Cooke County, TX | 125,580 |
| |
Wake Wind | Crosby & Floyd Counties, TX | 257,250 |
| (14 | ) |
Southern Power Total | | 1,473,730 |
| |
LANDFILL GAS FACILITY | | | |
Perdido | Escambia County, FL | | |
Gulf Power Total | | 3,200 |
| |
BIOMASS FACILITY | | | |
Nacogdoches | Sacul, TX | | |
Southern Power Total | | 115,500 |
| |
Total Generating Capacity | | 46,936,018 |
| |
Notes:
|
| |
(1) | See "Jointly-Owned Facilities" herein for additional information. |
(2) | Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively. |
(3) | Capacity shown is Alabama Power's portion (95.92%) of total plant capacity. |
(4) | Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3. Capacity shown for Gulf Power is 25% of Unit 3. |
(5) | Capacity shown is Georgia Power's portion (53.5%) of total plant capacity. |
(6) | Represents 50% of Plant Daniel Units 1 and 2, which are owned as tenants in common by Gulf Power and Mississippi Power. |
(7) | SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information. |
(8) | Capacity shown is Georgia Power's portion (50.1%) of total plant capacity. |
(9) | Capacity shown is Georgia Power's portion (45.7%) of total plant capacity. |
(10) | Generation is dedicated to a single industrial customer. |
(11) | The capacity shown is the gross capacity using natural gas fuel without supplemental firing. |
(12) | Capacity shown is Southern Power's portion (65%) of total plant capacity. |
(13) | Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant. |
(14) | Each facility is owned by Southern Power through a majority-owned subsidiary (90.1% Wake Wind, 66% Desert Stateline, and 51% for each of the following facilities: Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills-Blackwell, North Star, Roserock, and Tranquillity). The capacity shown in the table is 100% of the nameplate capacity for the respective facility. |
(15) | Southern Power is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of Southern Power's solar assets, which, if successful, is expected to close in the middle of 2018. |
Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition, and suitable for their intended purpose.
Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line, completed in 1984, extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is
paying a use fee over a 40-year period covering all expenses and the amortization of the original $57 million cost of the line. At December 31, 2017, the unamortized portion of this cost was approximately $13 million.
Mississippi Power owns a lignite mine and equipment that were intended to provide fuel for the Kemper IGCC. Mississippi Power also has acquired mineral reserves located around the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation activities to begin in 2018. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" of Mississippi Power in Item 7 herein and Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility – Lignite Mine and CO2 Pipeline Facilities" in Item 8 herein for additional information on the lignite mine.
In 2018, Mississippi Power will file a reserve margin plan which could impact Mississippi Power's generating stations as well as the generating stations jointly owned by Mississippi Power and other traditional electric operating companies. See BUSINESS in Item 1 herein under "Rate Matters – Integrated Resource Planning – Mississippi Power" for additional information.
In 2017, the maximum demand on the traditional electric operating companies, Southern Power, and SEGCO was 34,874,000 KWs and occurred on August 17, 2017. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies, Southern Power, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power, and SEGCO in 2017 was 30.8%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information.
Jointly-Owned Facilities
Alabama Power, Georgia Power, and Southern Power at December 31, 2017 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Percentage Ownership |
| | Total Capacity | | Alabama Power | | Power South | | Georgia Power | | OPC | | MEAG Power | | Dalton | | | Southern Power | | OUC | | FMPA | | KUA |
| | (MWs) | | | | | | | | | | | | | | | | | | | | | |
Plant Miller Units 1 and 2 | | 1,320 |
| | 91.8 | % | | 8.2 | % | | — | % | | — | % | | — | % | | — | % | | | — | % | | — | % | | — | % | | — | % |
Plant Hatch | | 1,796 |
| | — |
| | — |
| | 50.1 |
| | 30.0 |
| | 17.7 |
| | 2.2 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Vogtle Units 1 and 2 | | 2,320 |
| | — |
| | — |
| | 45.7 |
| | 30.0 |
| | 22.7 |
| | 1.6 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Scherer Units 1 and 2 | | 1,636 |
| | — |
| | — |
| | 8.4 |
| | 60.0 |
| | 30.2 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Plant Wansley | | 1,779 |
| | — |
| | — |
| | 53.5 |
| | 30.0 |
| | 15.1 |
| | 1.4 |
| | | — |
| | — |
| | — |
| | — |
|
Rocky Mountain | | 848 |
| | — |
| | — |
| | 25.4 |
| | 74.6 |
| | — |
| | — |
| | | — |
| | — |
| | — |
| | — |
|
Plant Stanton A | | 660 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 65.0 |
| | 28.0 |
| | 3.5 |
| | 3.5 |
|
Alabama Power and Georgia Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain) as agent for the joint owners. SCS provides operation and maintenance services for Plant Stanton A. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power's nuclear plants.
In addition, Georgia Power has commitments regarding a portion of a 5% interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC's disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power expense was $672 million, an increasefrom non-affiliates in Georgia Power's statements of $211 million, or 45.8%, as comparedincome in Item 8 herein. Also see Note 7 to the prior year. financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 herein for additional information.
Construction continues on Plant Vogtle Units 3 and 4, which are jointly owned by the Vogtle Owners (with each owner holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 herein.
Titles to Property
The increasetraditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants (other than certain pollution control facilities and the land on which five combustion turbine generators of Mississippi Power are located, which is held by easement) and other important units of the respective companies are owned in fee by such companies, subject only to the (1) liens pursuant to pollution control revenue bonds of Gulf Power on specific pollution control facilities at Plant Daniel, (2) liens pursuant to the assumption of debt obligations by Mississippi Power in connection with the acquisition of Plant Daniel Units 3 and 4, (3) liens pursuant to the agreements entered into with Mississippi Power's largest customer, Chevron Products Company (Chevron), on October 4, 2017, on the co-generation assets located at the Chevron refinery, (4) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4, and (5) liens associated with two PPAs assumed as part of the acquisition of the Mankato project in October 2016 by Southern Power Company. See Note 6 to the financial statements of Southern Company, Georgia Power, Gulf Power, Mississippi Power, and Southern Power under "Assets Subject to Lien," Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings," and Note 6 to the financial statements of Southern Company and Mississippi Power under "Plant Daniel Revenue Bonds" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.
Natural Gas
Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 6 to the financial statements of Southern Company Gas under "Long-Term Debt – First Mortgage Bonds" in Item 8 herein for additional information.
Distribution and Transmission Mains – Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2017, Southern Company Gas' gas distribution operations segment owned approximately 82,000 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.
Storage Assets – Gas Distribution Operations– Southern Company Gas owns and operates eight underground natural gas storage facilities in Illinois with a total inventory capacity of approximately 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.
Southern Company Gas also has five liquefied natural gas (LNG) plants located in Georgia, New Jersey, and Tennessee with total LNG storage capacity of approximately 7.6 Bcf. In addition, Southern Company Gas owns one propane storage facility in Virginia with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.
Storage Assets – All Other– Southern Company Gas subsidiaries own three high-deliverability natural gas storage and hub facilities that are operated by the gas midstream operations segment. Jefferson Island Storage & Hub, LLC operates a storage facility in Louisiana consisting of two salt dome gas storage caverns. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California. In addition, Southern Company Gas has a LNG facility in Alabama that produces LNG for Pivotal LNG, Inc. to support its business of selling LNG as a substitute fuel in various markets.
In August 2017, in connection with an ongoing integrity project into the salt dome gas storage caverns in Louisiana, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note 3 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
Jointly-Owned Properties– Southern Company Gas' gas midstream operations segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia that was primarilyplaced in service on August 1, 2017. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 4 to the financial statements of Southern Company and Southern Company Gas in Item 8 herein for additional information.
See Note 3 to the financial statements of each registrant in Item 8 herein for descriptions of legal and administrative proceedings discussed therein.
| |
Item 4. | MINE SAFETY DISCLOSURES |
Not applicable.
EXECUTIVE OFFICERS OF SOUTHERN COMPANY
(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
Age 60
Elected in 2003. Chairman and Chief Executive Officer since December 2010 and President since August 2010.
Art P. Beattie
Executive Vice President and Chief Financial Officer
Age 63
Elected in 2010. Executive Vice President and Chief Financial Officer since August 2010.
W. Paul Bowers
Executive Vice President
Age 61
Elected in 2001. Executive Vice President since February 2008 and Chief Executive Officer, President, and Director of Georgia Power since January 2011. Chairman of Georgia Power's Board of Directors since May 2014.
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer of Gulf Power
Age 48
Elected in 2012. Elected Chairman in July 2015 and President, Chief Executive Officer, and Director of Gulf Power since July 2012.
Mark A. Crosswhite
Executive Vice President
Age 55
Elected in 2010. Executive Vice President since July 2012 and President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.
Andrew W. Evans
Executive Vice President
Age 51
Elected in July 2016. Executive Vice President since July 2016. President of Southern Company Gas since May 2015 and Chief Executive Officer and Chairman of Southern Company Gas' Board of Directors since January 2016. Previously served as Chief Operating Officer of Southern Company Gas from May 2015 through December 2015 and Executive Vice President and Chief Financial Officer of Southern Company Gas from May 2006 through May 2015.
Kimberly S. Greene
Executive Vice President
Age 51
Elected in 2013. Executive Vice President and Chief Operating Officer since March 2014. Director of Southern Company Gas since July 2016. Previously served as President and Chief Executive Officer of SCS from April 2013 to February 2014. Before rejoining Southern Company, Ms. Greene served at Tennessee Valley Authority as Executive Vice President and Chief Generation Officer from 2011 through April 2013.
James Y. Kerr II
Executive Vice President and General Counsel
Age 53
Elected in 2014. Also serves as Chief Compliance Officer. Before joining Southern Company, Mr. Kerr was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC from 2008 through February 2014.
Stephen E. Kuczynski
Chairman, President, and Chief Executive Officer of Southern Nuclear
Age 55
Elected in 2011. Chairman, President, and Chief Executive Officer of Southern Nuclear since July 2011.
Mark S. Lantrip
Executive Vice President
Age 63
Elected in 2014. Chairman, President, and Chief Executive Officer of SCS since March 2014. Previously served as Treasurer of Southern Company from October 2007 to February 2014 and Executive Vice President of SCS from November 2010 to March 2014.
Nancy E. Sykes
Executive Vice President of SCS
Age 49
Elected in 2016. Also serves as Chief Human Resources Officer of SCS. Before joining Southern Company, Ms. Sykes served as vice president and chief human resources officer at United States Steel Corporation from May 2015 to November 2016. Previously served as Vice President, Human Resources Asia-Pacific at Goodyear Tire and Rubber Company from October 2012 until May 2015.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer of Mississippi Power
Age 53
Elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016. Previously served as Executive Vice President of Mississippi Power from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.
Christopher C. Womack
Executive Vice President
Age 59
Elected in 2008. Executive Vice President and President of External Affairs since January 2009.
The officers of Southern Company were elected at the first meeting of the directors following the last annual meeting of stockholders held on May 24, 2017, for a term of one year or until their successors are elected and have qualified.
EXECUTIVE OFFICERS OF ALABAMA POWER
(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer
Age 55
Elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.
Greg J. Barker
Executive Vice President
Age 54
Elected in 2016. Executive Vice President for Customer Services since February 2016. Previously served as Senior Vice President of Marketing and Economic Development from April 2012 to February 2016.
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
Age 58
Elected in 2010. Executive Vice President, Chief Financial Officer, and Treasurer since August 2010.
Zeke W. Smith
Executive Vice President
Age 58
Elected in 2010. Executive Vice President of External Affairs since November 2010.
James P. Heilbron
Senior Vice President and Senior Production Officer
Age 46
Elected in 2013. Senior Vice President and Senior Production Officer since March 2013. Previously served as Senior Vice President and Senior Production Officer of Southern Power Company from July 2010 to February 2013.
R. Scott Moore
Senior Vice President
Age 50
Elected in 2017. Senior Vice President of Power Delivery since May 2017. Previously served as Vice President of Transmission from August 2012 to May 2017.
The officers of Alabama Power were elected at the meeting of the directors held on April 28, 2017 for a term of one year or until their successors are elected and have qualified, except for Mr. Moore, whose election as Senior Vice President was effective May 20, 2017.
EXECUTIVE OFFICERS OF MISSISSIPPI POWER
(Identification of executive officers of Mississippi Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2017.
Anthony L. Wilson
Chairman, President, and Chief Executive Officer
Age 53
Elected in 2015. President since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board since August 2016. Previously served as Executive Vice President from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.
John W. Atherton
Vice President
Age 57
Elected in 2004. Vice President of Corporate Services and Community Relations since October 2012.
A. Nicole Faulk
Vice President
Age 44
Elected in 2015. Vice President of Customer Services Organization effective April 2015. Previously served as Region Vice President for the West Region of Georgia Power from March 2015 through April 2015 and Region Manager for the Metro West Region of Georgia Power from December 2011 to March 2015.
Moses H. Feagin
Vice President, Treasurer, and Chief Financial Officer
Age 53
Elected in 2010. Vice President, Treasurer, and Chief Financial Officer since August 2010.
R. Allen Reaves, Jr.
Vice President
Age 58
Elected in 2010. Vice President and Senior Production Officer since August 2010.
Billy F. Thornton
Vice President
Age 57
Elected in 2012. Vice President of External Affairs since October 2012.
The officers of Mississippi Power were elected at the meeting of the directors held on May 1, 2017 for a term of one year or until their successors are elected and have qualified.
PART II
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Item 5. | MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
(a)(1) The common stock of Southern Company is listed and traded on the NYSE. The common stock is also traded on regional exchanges across the U.S. The high and low stock prices as reported on the NYSE for each quarter of the past two years were as follows:
|
| | | | | | | | |
| | High | | Low |
2017 | | | | |
First Quarter | | $ | 51.47 |
| | $ | 47.57 |
|
Second Quarter | | 51.97 |
| | 47.87 |
|
Third Quarter | | 50.80 |
| | 46.71 |
|
Fourth Quarter | | 53.51 |
| | 47.92 |
|
2016 | | | | |
First Quarter | | $ | 51.73 |
| | $ | 46.00 |
|
Second Quarter | | 53.64 |
| | 47.62 |
|
Third Quarter | | 54.64 |
| | 50.00 |
|
Fourth Quarter | | 52.23 |
| | 46.20 |
|
There is no market for the other registrants' common stock, all of which is owned by Southern Company.
(a)(2) Number of Southern Company's common stockholders of record at January 31, 2018: 120,413
Each of the other registrants have one common stockholder, Southern Company.
(a)(3) Dividends on each registrant's common stock are payable at the discretion of their respective board of directors and depend upon earnings, financial condition, and other factors. The dividends on common stock declared by Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, and Southern Company Gas to their stockholder(s) for the past two years are set forth below. No dividends were declared by Mississippi Power on its common stock in 2016 or 2017. Southern Company Gas' dividends are only shown for periods subsequent to the Merger.
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| | | | | | | | | | |
Registrant | | Quarter | | 2017 | | 2016 |
| | | | (in thousands) |
Southern Company | | First | | $ | 555,791 |
| | $ | 496,718 |
|
| | Second | | 578,525 |
| | 526,267 |
|
| | Third | | 581,501 |
| | 529,876 |
|
| | Fourth | | 584,015 |
| | 551,110 |
|
Alabama Power | | First | | 178,507 |
| | 191,206 |
|
| | Second | | 178,507 |
| | 191,206 |
|
| | Third | | 178,507 |
| | 191,206 |
|
| | Fourth | | 178,507 |
| | 191,206 |
|
Georgia Power | | First | | 320,242 |
| | 326,269 |
|
| | Second | | 320,242 |
| | 326,269 |
|
| | Third | | 320,242 |
| | 326,269 |
|
| | Fourth | | 320,242 |
| | 326,269 |
|
Gulf Power | | First | | 31,250 |
| | 30,017 |
|
| | Second | | 31,250 |
| | 30,017 |
|
| | Third | | 31,250 |
| | 30,017 |
|
| | Fourth | | 71,250 |
| | 30,017 |
|
Southern Power Company | | First | | 79,211 |
| | 68,082 |
|
| | Second | | 79,211 |
| | 68,082 |
|
| | Third | | 79,211 |
| | 68,082 |
|
| | Fourth | | 79,211 |
| | 68,082 |
|
Southern Company Gas | | First | | 110,641 |
| | — |
|
| | Second | | 110,641 |
| | — |
|
| | Third | | 110,641 |
| | 62,750 |
|
| | Fourth | | 110,641 |
| | 62,750 |
|
The dividend paid per share of Southern Company's common stock was 56.00¢ for the first quarter 2017 and 58.00¢ each for the second, third, and fourth quarters of 2017. In 2016, Southern Company paid a dividend per share of 54.25¢ for the first quarter and 56.00¢ each for the second, third, and fourth quarters.
The traditional electric operating companies and Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. The authority of the natural gas distribution utilities to pay dividends to Southern Company Gas is subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates. Additionally, Elizabethtown Gas is restricted by its policy, as established by the New Jersey Board of Public Utilities, to 70% of its quarterly net income it can dividend to Southern Company Gas. Also, as stipulated in the New Jersey Board of Public Utilities' order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade.
(a)(4) Securities authorized for issuance under equity compensation plans.
See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(b) Use of Proceeds
Not applicable.
(c) Issuer Purchases of Equity Securities
None.
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Item 6. | SELECTED FINANCIAL DATA |
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Item 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each of the registrants in Item 7 herein and Note 1 of each of the registrant's financial statements under "Financial Instruments" in Item 8 herein. See also Notes 10 and 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Notes 9 and 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Notes 8 and 9 to the financial statements of Southern Power in Item 8 herein.
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Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO 2017 FINANCIAL STATEMENTS
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Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
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Item 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures.
As of the end of the period covered by this Annual Report on Form 10-K, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
(a) Management's Annual Report on Internal Control Over Financial Reporting.
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Management's Report on Internal Control Over Financial Reporting | Page |
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| |
| |
| |
| |
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(b) Attestation Report of the Registered Public Accounting Firm.
The report of Deloitte & Touche LLP, Southern Company's independent registered public accounting firm, regarding Southern Company's Internal Control over Financial Reporting is included on page II-9 of this Form 10-K. This report is not applicable to Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas as these companies are not accelerated filers or large accelerated filers.
(c) Changes in internal control over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the fourth quarter 2017 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
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Item 9B. | OTHER INFORMATION |
None.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company and Subsidiary Companies 2017 Annual Report
The management of The Southern Company (Southern Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of Southern Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company's internal control over financial reporting was effective as of December 31, 2017.
Deloitte & Touche LLP, as auditors of Southern Company's financial statements, has issued an attestation report on the effectiveness of Southern Company's internal control over financial reporting as of December 31, 2017, which is included herein.
/s/ Thomas A. Fanning
Thomas A. Fanning
Chairman, President, and Chief Executive Officer
/s/ Art P. Beattie
Art P. Beattie
Executive Vice President and Chief Financial Officer
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of The Southern Company and Subsidiary Companies (the Company) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements (pages II-64 to II-151) referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting (page II-8). Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a 35.3% increasetest basis, evidence regarding the amounts and disclosures in the averagefinancial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 20, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of Mississippi Power's Kemper County energy facility |
2013 ARP | Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
AFUDC | Allowance for funds used during construction |
Alabama Power | Alabama Power Company |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest |
Bechtel | Bechtel Power Corporation |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
COD | Commercial operation date |
Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
Cooperative Energy | Electric cooperative in Mississippi |
CPCN | Certificate of public convenience and necessity |
CWIP | Construction work in progress |
Dalton Pipeline | A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest |
DOE | U.S. Department of Energy |
Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FFB | Federal Financing Bank |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe) |
Interim Assessment Agreement | Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
LIFO | Last-in, first-out |
Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
LTSA | Long-term service agreement |
Merger | The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation |
Mirror CWIP | A regulatory liability used by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility, which were subsequently refunded to customers |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MPUS | Mississippi Public Utilities Staff |
MW | Megawatt |
natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Inc., Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas) |
NCCR | Georgia Power's Nuclear Construction Cost Recovery |
NDR | Alabama Power's Natural Disaster Reserve |
New Jersey BPU | New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas |
Nicor Gas | Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
PennEast Pipeline | PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest |
PowerSecure | PowerSecure, Inc. |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PSC | Public Service Commission |
PTC | Production tax credit |
Rate CNP | Alabama Power's Rate Certificated New Plant |
Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Alabama Power's Rate Energy Cost Recovery |
Rate NDR | Alabama Power's Rate Natural Disaster Reserve |
Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
DEFINITIONS
(continued)
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| |
Term | Meaning |
SO2 | Sulfur dioxide |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | The Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries |
Southern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
Toshiba | Toshiba Corporation, parent company of Westinghouse |
Toshiba Guarantee | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
VCM | Vogtle Construction Monitoring |
Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
Vogtle Services Agreement | The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear |
Westinghouse | Westinghouse Electric Company LLC |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company and Subsidiary Companies 2017 Annual Report
OVERVIEW
Business Activities
The Southern Company (Southern Company or the Company) is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. See FUTURE EARNINGS POTENTIAL – "General" herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
Many factors affect the opportunities, challenges, and risks of the Southern Company system's electricity and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems.
The traditional electric operating companies and natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 3 to the financial statements under "Regulatory Matters" for additional information.
Another major factor affecting the Southern Company system's businesses is the profitability of the competitive market-based wholesale generating business. Southern Power's strategy is to create value through various transactions including acquisitions and sales of assets, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities. Southern Power is also currently pursuing the sale of a portion of equity interests in its solar assets. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.
In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than nine million electric and gas utility customers, the Southern Company system continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per KWH purchased.share (EPS). Southern Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system.
See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
II-19Kemper County Energy Facility Status
The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
the CO2 pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket).
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants). In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.
On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with Mississippi Power's Performance Evaluation Plan (PEP), excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2017.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
See Note 3 to the financial statements under "Nuclear Construction" for additional information.
Earnings
Consolidated net income attributable to Southern Company was $842 million in 2017, a decrease of $1.6 billion, or 65.6%, from the prior year. The decrease was primarily due to pre-tax charges of $3.4 billion ($2.4 billion after tax) related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases of $240 million in net income from Southern Company Gas (excluding the impact of $111 million in additional expense related to the Tax Reform Legislation) reflecting the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, $264 million related to net tax benefits from the Tax Reform Legislation, higher retail electric revenues resulting from increases in base rates partially offset by milder weather and lower customer usage, and increases in renewable energy sales at Southern Power. These increases were partially offset by higher interest and depreciation and amortization.
Consolidated net income attributable to Southern Company was $2.4 billion in 2016, an increase of $81 million, or 3.4%, from the prior year. Consolidated net income increased by $114 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016. Also contributing to the increase were higher retail electric revenues resulting from non-fuel retail rate increases and warmer weather, primarily in the third quarter 2016, as well as the 2015 correction of a Georgia Power billing error, partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. Additionally, the increase was due to increases in income tax benefits and renewable energy sales at Southern Power. These increases were partially offset by higher interest expense, non-fuel operations and maintenance expenses, depreciation and amortization, lower wholesale capacity revenues, and higher estimated losses associated with the Kemper IGCC.
See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Basic EPS was $0.84 in 2017, $2.57 in 2016, and $2.60 in 2015. Diluted EPS, which factors in additional shares related to stock-based compensation, was $0.84 in 2017, $2.55 in 2016, and $2.59 in 2015. EPS for 2017 was negatively impacted by $0.04 per share as a result of an increase in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.
Dividends
Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.30 in 2017, $2.22 in 2016, and $2.15 in 2015. In January 2018, Southern Company declared a quarterly dividend of 58 cents per share. This is the 281st consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2017, the dividend payout ratio was 273% compared to 86% for 2016. The increase was due to a significant reduction in earnings resulting from charges related to the Kemper IGCC. See "Earnings" and RESULTS OF OPERATIONS – "Electricity Business – Estimated Loss on Kemper IGCC" herein and Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
RESULTS OF OPERATIONS
Discussion of the results of operations is divided into three parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.
|
| | | | | | | | | | | |
| Amount |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Electricity business | $ | 878 |
| | $ | 2,571 |
| | $ | 2,401 |
|
Gas business | 243 |
| | 114 |
| | — |
|
Other business activities | (279 | ) | | (237 | ) | | (34 | ) |
Net Income | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Electricity Business
Southern Company's electric utilities generate and sell electricity to retail and wholesale customers.
A condensed statement of income for the electricity business follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 | | 2016 |
| (in millions) |
Electric operating revenues | $ | 18,540 |
| | $ | 599 |
| | $ | 499 |
|
Fuel | 4,400 |
| | 39 |
| | (389 | ) |
Purchased power | 863 |
|
| 113 |
| | 105 |
|
Cost of other sales | 69 |
| | 11 |
| | 58 |
|
Other operations and maintenance | 4,340 |
| | (183 | ) | | 231 |
|
Depreciation and amortization | 2,457 |
| | 224 |
| | 213 |
|
Taxes other than income taxes | 1,063 |
| | 24 |
| | 44 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 2,934 |
| | 63 |
|
Total electric operating expenses | 16,554 |
| | 3,162 |
| | 325 |
|
Operating income | 1,986 |
| | (2,563 | ) | | 174 |
|
Allowance for equity funds used during construction | 152 |
| | (48 | ) | | (26 | ) |
Interest expense, net of amounts capitalized | 1,011 |
| | 80 |
| | 157 |
|
Other income (expense), net | (83 | ) | | (8 | ) | | (43 | ) |
Income taxes | 82 |
| | (1,009 | ) | | (235 | ) |
Net income | 962 |
| | (1,690 | ) | | 183 |
|
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | (7 | ) | | (9 | ) |
Net income attributable to noncontrolling interests | 46 |
| | 10 |
| | 22 |
|
Net Income Attributable to Southern Company | $ | 878 |
| | $ | (1,693 | ) | | $ | 170 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Electric Operating Revenues
Electric operating revenues for 2017 were $18.5 billion, reflecting a $599 million increase from 2016. Details of electric operating revenues were as follows:
|
| | | | | | | |
| Amount |
| 2017 | | 2016 |
| (in millions) |
Retail electric — prior year | $ | 15,234 |
| | $ | 14,987 |
|
Estimated change resulting from — | | | |
Rates and pricing | 508 |
| | 427 |
|
Sales decline | (71 | ) | | (35 | ) |
Weather | (281 | ) | | 153 |
|
Fuel and other cost recovery | (60 | ) | | (298 | ) |
Retail electric — current year | 15,330 |
| | 15,234 |
|
Wholesale electric revenues | 2,426 |
| | 1,926 |
|
Other electric revenues | 681 |
| | 698 |
|
Other revenues | 103 |
| | 83 |
|
Electric operating revenues | $ | 18,540 |
| | $ | 17,941 |
|
Percent change | 3.3 | % | | 2.9 | % |
Retail electric revenues increased $96 million, or 0.6%, in 2017 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2017 was primarily due to a Rate RSE increase at Alabama Power effective in January 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base rates effective July 2017 at Gulf Power. See Note 3 to the financial statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.
Retail electric revenues increased $247 million, or 1.6%, in 2016 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2016 was primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power and the implementation of rates at Mississippi Power for certain Kemper County energy facility in-service assets, effective September 2015. These increases were partially offset by accruals in 2016 for expected refunds at Alabama Power and Georgia Power. See Note 3 to the financial statements under "Kemper County Energy Facility – Rate Recovery" for additional information.
See Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate RSE" and " – Rate CNP Compliance" and "Nuclear Construction" and Note 1 to the financial statements under "General" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.
Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
result, the Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
Wholesale electric revenues from power sales were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Capacity and other | $ | 838 |
| | $ | 771 |
| | $ | 875 |
|
Energy | 1,588 |
| | 1,155 |
| | 923 |
|
Total | $ | 2,426 |
| | $ | 1,926 |
| | $ | 1,798 |
|
In 2017, wholesale revenues increased $500 million, or 26.0%, as compared to the prior year due to a $433 million increase in energy revenues and a $67 million increase in capacity revenues, primarily at Southern Power. The increase in energy revenues was primarily due to increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to a PPA related to new natural gas facilities and additional customer capacity requirements.
In 2016, wholesale revenues increased $128 million, or 7.1%, as compared to the prior year due to a $232 million increase in energy revenues, partially offset by a $104 million decrease in capacity revenues. The increase in energy revenues was primarily due to increases in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decrease in capacity revenues was primarily due to the expiration of wholesale contracts at Georgia Power and Gulf Power, the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, and unit retirements at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power in the first quarter 2016.
Other Electric Revenues
Other electric revenues decreased $17 million, or 2.4%, and increased $41 million, or 6.2%, in 2017 and 2016, respectively, as compared to the prior years. The 2017 decrease was primarily due to a $15 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power. The 2016 increase was primarily due to a $14 million increase in customer temporary facilities services revenues and a $12 million increase in outdoor lighting revenues at Georgia Power, primarily attributable to LED conversions.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:
|
| | | | | | | | | | | | | | |
| Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in billions) | | | | | | | | |
Residential | 50.5 |
| | (5.3 | )% | | 2.3 | % | | (0.3 | )% | | 0.2 | % |
Commercial | 52.3 |
| | (2.6 | ) | | 0.4 |
| | (0.9 | ) | | (1.0 | ) |
Industrial | 52.8 |
| | — |
| | (2.1 | ) | | — |
| | (2.2 | ) |
Other | 0.9 |
| | (4.0 | ) | | (1.7 | ) | | (3.9 | ) | | (1.7 | ) |
Total retail | 156.5 |
| | (2.6 | ) | | 0.2 |
| | (0.4 | )% | | (1.0 | )% |
Wholesale | 49.0 |
| | 32.4 |
| | 21.4 |
| | | | |
Total energy sales | 205.5 |
| | 3.9 | % | | 3.6 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales decreased 4.2 billion KWHs in 2017 as compared to the prior year. This decrease was primarily due to milder weather and decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales decreased primarily due to decreased customer usage resulting from an increase in penetration of
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
energy-efficient residential appliances and an increase in multi-family housing, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH energy sales were flat primarily due to decreased sales in the paper, stone, clay, and glass, transportation, and chemicals sectors, offset by increased sales in the primary metals and textile sectors. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.
Retail energy sales increased 261 million KWHs in 2016 as compared to the prior year. This increase was primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 and customer growth, partially offset by decreased customer usage. The decrease in industrial KWH energy sales was primarily due to decreased sales in the primary metals, chemicals, paper, pipeline, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions constrained growth in the industrial sector in 2016. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased primarily due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. Household income, one of the primary drivers of residential customer usage, had modest growth in 2016.
See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.
Other Revenues
Other revenues increased $20 million, or 24.1%, in 2017 as compared to the prior year. The 2017 increase was primarily due to additional third party infrastructure services.
Other revenues increased $83 million in 2016 as compared to the prior year. The 2016 increase was primarily due to revenues from certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as other revenues for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these revenues were included in other income (expense), net.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses for the electric utilities. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Total generation (in billions of KWHs) | 194 |
| | 188 |
| | 187 |
|
Total purchased power (in billions of KWHs) | 20 |
| | 19 |
| | 13 |
|
Sources of generation (percent) — | | | | | |
Gas | 46 |
| | 46 |
| | 46 |
|
Coal | 30 |
| | 33 |
| | 34 |
|
Nuclear | 16 |
| | 16 |
| | 16 |
|
Hydro | 2 |
| | 2 |
| | 3 |
|
Other | 6 |
| | 3 |
| | 1 |
|
Cost of fuel, generated (in cents per net KWH) — | | | | | |
Gas | 2.79 |
| | 2.48 |
| | 2.60 |
|
Coal | 2.81 |
| | 3.04 |
| | 3.55 |
|
Nuclear | 0.79 |
| | 0.81 |
| | 0.79 |
|
Average cost of fuel, generated (in cents per net KWH) | 2.44 |
| | 2.40 |
| | 2.64 |
|
Average cost of purchased power (in cents per net KWH)(*) | 5.19 |
| | 4.81 |
| | 6.11 |
|
| |
(*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In 2017, total fuel and purchased power expenses were $5.3 billion, an increase of $152 million, or 3.0%, as compared to the prior year. The increase was primarily the result of a $196 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $44 million net decrease in the volume of KWHs generated and purchased.
In 2016, total fuel and purchased power expenses were $5.1 billion, a decrease of $284 million, or 5.3%, as compared to the prior year. The decrease was primarily the result of a $650 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $366 million increase in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Fuel
In 2017, fuel expense was $4.4 billion, an increase of $39 million, or 0.9%, as compared to the prior year. The increase was primarily due to a 12.5% increase in the average cost of natural gas per KWH generated and a 2.8% increase in the volume of KWHs generated by natural gas, partially offset by a 7.9% decrease in the volume of KWHs generated by coal and a 7.6% decrease in the average cost of coal per KWH generated.
In 2016, fuel expense was $4.4 billion, a decrease of $389 million, or 8.2%, as compared to the prior year. The decrease was primarily due to a 14.4% decrease in the average cost of coal per KWH generated, a 4.6% decrease in the average cost of natural gas per KWH generated, and a 2.7% decrease in the volume of KWHs generated by coal, partially offset by a 3.5% increase in the volume of KWHs generated by natural gas.
Purchased Power
In 2017, purchased power expense was $863 million, an increase of $113 million, or 15.1%, as compared to the prior year. The increase was primarily due to a 7.9% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, and a 5.0% increase in the volume of KWHs purchased.
In 2016, purchased power expense was $750 million, an increase of $105 million, or 16.3%, as compared to the prior year. The increase was primarily due to a 45.6% increase in the volume of KWHs purchased, partially offset by a 21.3% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Other Sales
Cost of other sales were $69 million and $58 million in 2017 and 2016, respectively. These costs were related to certain non-regulated sales of products and services by the traditional electric operating companies that were reclassified as cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. In prior periods, these costs were included in other income (expense), net.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased $33decreased $183 million, or 0.8%4.0%, in 20152017 as compared to the prior year. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power that contributed to decreases of $85 million in generation maintenance costs, $49 million in other employee compensation and benefits, $46 million in transmission and distribution overhead line maintenance, and $22 million in customer accounts, service, and sales costs. Other factors include a $40 million increase in gains from sales of assets at Georgia Power and a $34 million decrease in scheduled outage and maintenance costs at generation facilities. These decreases were partially offset by a $56 million increase associated with new facilities at Southern Power, a $37 million increase in transmission and distribution costs primarily due to vegetation management at Alabama Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a rate case settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement).
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Other operations and maintenance expenses increased $231 million, or 5.4%, in 2016 as compared to the prior year. The increase was primarily related to an $84a $76 million increase in employee compensationtransmission and benefits including pension costs,distribution expenses primarily related to overhead line maintenance, a $62$37 million decrease in gains from sales of assets at Georgia Power, a $36 million charge in connection with cost containment activities at Georgia Power, and a $35 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. Additionally, the increase was due to a $19 million increase in generation expenses primarily related to environmental costs, a $19 million increase in business development and support expenses at Southern Power, and an $11 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs, partially offset by a $99 million decrease in transmission and distribution costs primarily related to reduced overhead line maintenance and gains from sales of transmission assets and a $32 million decrease in scheduled outage and maintenance costs at generation facilities.
Other operations and maintenance expenses increased $481facilities, partially offset by a $41 million or 12.7%,net decrease in 2014 as compared to the prior year. The increase was primarily related to increases of $149 million in scheduled outage costs at generation facilities, $103 million in other generation expenses primarily related to commodity and labor costs, $103 million in transmission and distribution costs primarily related to overhead line maintenance, $42 million in net employee compensation and benefits, including pension costs, and $31 million in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs.costs.
Production expenses and transmission and distribution expenses fluctuate from year to year due to variations in outage and maintenance schedules and normal changes in the cost of labor and materials.
Depreciation and Amortization
Depreciation and amortization increased $91$224 million, or 4.7%10.0%, in 20152017 as compared to the prior year. The increase reflects $203 million related to additional plant in service at the traditional electric operating companies and Southern Power and a $13 million increase in amortization related to environmental compliance at Mississippi Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.
Depreciation and amortization increased $213 million, or 10.5%, in 2016 as compared to the prior year primarily due to the amortization of $120 million of the regulatory liability for other cost of removal obligations in 2014 at Alabama Power and increases in additional plant in service at the traditional electric operating companies and Southern Power, partially offset by a decrease as a result of a reduction in depreciation rates at Alabama Power effective January 1, 2015, a decrease due to unit retirements at Georgia Power, and a reduction in depreciation at Gulf Power as authorized in the 2013 rate case settlement agreement approved by the Florida PSC. See Note 3 to the financial statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" for additional information.
Depreciation and amortization increased $43 million, or 2.3%, in 2014 as compared to the prior year primarily due to increases in depreciation rates related to environmental assets and the amortization of certain regulatory assets at Alabama Power and the completion of the amortization of certain regulatory liabilities at Georgia Power. Also contributing to the increase were increases at Southern Power in plant in service related to the addition of solar facilities in 2013 and 2014, an increase related to equipment retirements resulting from accelerated outage work, and additional component depreciation as a result of increased production. These increases were largely offset by the amortization of $120 million of the regulatory liability for other cost of removal obligations at Alabama Power.
See Note 1 to the financial statements under "Regulatory"Regulatory Assets and Liabilities"Liabilities" and "Depreciation"Depreciation and Amortization" and Note 3 to the financial statements under "Retail Regulatory Matters – Alabama Power – Rate CNP" and "– Cost of Removal Accounting Order"Amortization" for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $16$24 million, or 1.6%2.3%, in 20152017 as compared to the prior year primarily due to an increase in ad valorem and property taxes.taxes due to new facilities at Southern Power.
Taxes other than income taxes increased $47$44 million, or 5.0%4.4%, in 20142016 as compared to the prior year primarily due to increases of $34 millionan increase in municipal franchise fees relatedproperty taxes due to higher retail revenuesassessed value of property at the traditional electric operating companies, increases in 2014state and $16 millionmunicipal utility license tax bases at Alabama Power, an increase in payroll taxes primarily related to higher employee benefits.at Georgia Power, and an increase in franchise taxes at Mississippi Power.
Estimated Loss on Kemper IGCC
In 20152017, 2016, and 2014,2015, estimated probable losses on the Kemper IGCC of $365$3.4 billion, $428 million, and $868$365 million, respectively, were recorded at Southern Company. TheseOn June 28, 2017, Mississippi Power suspended the gasifier portion of the project and recorded a charge to earnings for the remaining $2.8 billion book value of the gasifier portion of the project. Prior to the suspension, Mississippi Power recorded losses reflectfor revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by theInitial DOE under the Clean Coal Power Initiative Round 2 (DOE Grants)Grants and excluding the costCost Cap Exceptions.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Allowance for Equity Funds Used During Construction
AFUDC equity decreased $48 million, or 24.0%, in 2017 as compared to the prior year primarily due to Mississippi Power's suspension of the lignite mineKemper IGCC project in June 2017.
AFUDC equity decreased $26 million, or 11.5%, in 2016 as compared to the prior year primarily due to environmental and equipment,generation projects being placed in service at Alabama Power and Gulf Power, partially offset by a higher AFUDC rate and an increase in Kemper County energy facility CWIP subject to AFUDC at Mississippi Power prior to the costsuspension of the COgasifier portion of the project.
See Note 3 to the financial statements under "2Kemper County Energy Facility pipeline facilities, AFUDC," for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $80 million, or 8.6%, in 2017 as compared to the prior year primarily due to an increase in average outstanding long-term debt, primarily at Southern Power and certain general exceptions, including change of law, force majeure,Georgia Power, and beneficial capital (which exists whena $37 million decrease in interest capitalized, primarily at Southern Power and Mississippi Power, demonstrates that the purpose andpartially offset by a net reduction of $36 million
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
effect offollowing Mississippi Power's settlement with the construction cost increase isIRS related to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).research and experimental deductions. See Note 35 to the financial statements under "Integrated Coal Gasification Combined Cycle""Unrecognized Tax Benefits" for additional information.
Allowance for Equity Funds Used During Construction
AFUDC equity decreased $19Interest expense, net of amounts capitalized increased $157 million, or 7.8%20.3%, in 20152016 as compared to the prior year primarily due to a reduction in the AFUDC rate at Mississippi Power, as well as placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014, partially offset by an increase in construction projects related to environmental and steam generation at Alabama Power.
AFUDC equity increased $55 million, or 28.9%, in 2014 as compared to the prior year primarily due to additional capital expenditures at the traditional operating companies, primarily related to environmental and transmission projects, as well as Mississippi Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased $20 million, or 2.5%, in 2015 as compared to the prior year primarily due to a decrease of $58 million at Mississippi Power related to the termination of an agreement for SMEPA to purchase a portion of the Kemper IGCC which required the return of SMEPA's deposits at a lower rate of interest than accrued and a $14 million decrease primarily due to an increase in capitalized interest associated with the construction of solar facilities at Southern Power, partially offset by a $46 million increase due to higher average outstanding long-term debt balances at the traditional operating companies.
Interest expense, net of amounts capitalized increased $6 million, or 0.8%, in 2014 as compared to the prior year primarily due to a higher amount of outstanding long-term debt and an increase in interest expense resulting fromat Southern Power related to additional debt issued primarily to fund its growth strategy and continuous construction program, increases in both the deposits received byaverage outstanding long-term debt balance and the average interest rate at the traditional electric operating companies, and the May 2015 termination of an asset purchase agreement between Mississippi Power in January and October 2014 from SMEPA, partially offset by a decrease inCooperative Energy and the resulting reversal of accrued interest expenseon related to the refinancing of long-term debt at lower rates and an increase in capitalized interest.deposits.
See Note 6 to the financial statements for additional information.
Other Income (Expense), Net
Other income (expense), net increased $19decreased $8 million, or 26.0%10.7%, in 20152017 as compared to the prior year primarily due to increases in charitable donations. The change also includes an increase of $9$159 million in wholesale operating fee revenues, an increasecurrency losses arising from a translation of $9 million in customer contributions in aid of construction at Georgia Power, and an increase due to Mississippi Power's $7 million settlement with the Sierra Club in 2014, partiallyeuro-denominated fixed-rate notes into U.S. dollars, fully offset by a decreasean equal change in sales of non-utility propertygains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Alabama Power.Southern Power.
Other income (expense), net decreased $18$43 million, or 32.7%134.4%, in 20142016 as compared to the prior year primarily due to the reclassification of revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. The net amounts reclassified were $25 million. Also contributing to the decrease was an $8 million decrease in customer contributions in aid of construction and a $6 million decrease in wholesale operating fee revenuesrevenue at Georgia Power and $7 million associated with Mississippi Power's settlement with the Sierra Club.Power.
Income Taxes
Income taxes increased $273 million,decreased $1.0 billion, or 25.9%92.5%, in 20152017 as compared to the prior year primarily due to a reduction$809 million in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recordedat Mississippi Power and $346 million in 2014 and higher pre-tax earnings, partially offset by increased federal incomenet tax benefits related to ITCs at Southern Power in 2015.resulting from the Tax Reform Legislation.
Income taxes increased $118decreased $235 million, or 12.6%17.7%, in 20142016 as compared to the prior year primarily due to higher pre-tax earnings, partially offset by an increase in non-taxable AFUDC equity and an increase inincreased federal income tax benefits related to ITCs on Southern Powerfor solar projectsplants placed in service and PTCs from wind generation at Southern Power in 2014.2016.
See Note 5 to the financial statements for additional information.
Gas Business
Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
On July 1, 2016, Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The condensed statements of income herein includes Southern Company Gas' results of operations since July 1, 2016. See Note 12 to the financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger, including certain pro forma results of operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
A condensed statement of income for the gas business follows:
|
| | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 |
| (in millions) |
Operating revenues | $ | 3,920 |
| | $ | 2,268 |
|
Cost of natural gas | 1,601 |
| | 988 |
|
Cost of other sales | 29 |
| | 19 |
|
Other operations and maintenance | 940 |
| | 417 |
|
Depreciation and amortization | 501 |
| | 263 |
|
Taxes other than income taxes | 184 |
| | 113 |
|
Total operating expenses | 3,255 |
| | 1,800 |
|
Operating income | 665 |
| | 468 |
|
Earnings from equity method investments | 106 |
| | 46 |
|
Interest expense, net of amounts capitalized | 200 |
| | 119 |
|
Other income (expense), net | 39 |
| | 25 |
|
Income taxes | 367 |
| | 291 |
|
Net income | $ | 243 |
| | $ | 129 |
|
The changes in the table above for Southern Company Gas reflect the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016. Additionally, earnings from equity method investments include Southern Company Gas' acquisition of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG) completed in September 2016. See Note 12 to the financial statements under "Southern Company Gas" for additional information on Southern Company Gas' investment in SNG.
Seasonality of Results
During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected to Southern Company Gas' distribution systems, and natural gas usage is higher in periods of colder weather. Occasionally in the summer, operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For 2017, the percentage of operating revenues and net income generated during the Heating Season (January through March and November through December) were 67.3% and 73.7%, respectively. For July 1, 2016 through December 31, 2016, the percentage of operating revenues and net income generated during the Heating Season (November and December) were 67.1% and 96.5%, respectively. The 2017 net income generated during the Heating Season was significantly impacted by additional tax expense recorded in the fourth quarter resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein for additional information.
Other Business Activities
Southern Company's other business activities include the parent company (which does not allocate operating expenses to business units), products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, and investments in leveraged lease projects and telecommunications. These businesses are classified in general categories and may comprise one or both of the following subsidiaries: PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure; Southern Company Holdings, Inc. (Southern Holdings) invests in various projects, including leveraged lease projects,projects; and SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast.
II-21On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure for an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company. See Note 12 to the financial statements under "Southern Company – Acquisition of PowerSecure" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast.
On February 24, 2016, Southern Company entered into an Agreement and Plan of Merger to acquire PowerSecure International, Inc. Under the terms of this merger agreement, the stockholders of PowerSecure International, Inc. will be entitled to receive $18.75 in cash for each share of common stock in a transaction with a total purchase price of approximately $431 million. Following this transaction, PowerSecure International, Inc. will become a wholly-owned subsidiary of Southern Company. This transaction is expected to close by the end of the second quarter 2016, subject to, among other items, approval by PowerSecure International, Inc. stockholders and notification, clearance, and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
A condensed statement of income for Southern Company's other business activities follows:
| | | Amount | | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Operating revenues | $ | 47 |
| | $ | (14 | ) | | $ | 9 |
| $ | 571 |
| | $ | 268 |
| | $ | 256 |
|
Cost of other sales | | 415 |
| | 223 |
| | 192 |
|
Other operations and maintenance | 124 |
| | 29 |
| | 27 |
| 201 |
| | 7 |
| | 70 |
|
Depreciation and amortization | 14 |
| | (2 | ) | | 1 |
| 52 |
| | 21 |
| | 17 |
|
Taxes other than income taxes | 2 |
| | — |
| | — |
| 3 |
| | — |
| | 1 |
|
Total operating expenses | 140 |
| | 27 |
| | 28 |
| 671 |
| | 251 |
| | 280 |
|
Operating income (loss) | (93 | ) | | (41 | ) | | (19 | ) | (100 | ) | | 17 |
| | (24 | ) |
Interest income | 1 |
| | — |
| | — |
| |
Interest expense | | 483 |
| | 178 |
| | 239 |
|
Other income (expense), net | (8 | ) | | (18 | ) | | 36 |
| (3 | ) | | 28 |
| | (24 | ) |
Interest expense | 66 |
| | 25 |
| | 5 |
| |
Income taxes | (132 | ) | | (56 | ) | | 10 |
| |
Income taxes (benefit) | | (307 | ) | | (91 | ) | | (84 | ) |
Net income (loss) | $ | (34 | ) | | $ | (28 | ) | | $ | 2 |
| $ | (279 | ) | | $ | (42 | ) | | $ | (203 | ) |
Operating Revenues
Southern Company's non-electric operating revenues for these other business activities decreased $14increased $268 million, or 23.0%88.4%, in 20152017 as compared to the prior year. The decreaseincrease was primarily relatedthe result of the inclusion of PowerSecure results for the 12-month period in 2017 compared to lower operating revenues at Southern Holdings due to higher billingseight months in 2014 related to work performed on a generating plant outage and decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry.2016. Non-electric operating revenues for these other businessesbusiness activities increased $9$256 million, or 17.3%544.7%, in 20142016 as compared to the prior year. The increase was primarily related to higher operating revenues at Southern Holdings due to higher billingsfrom products and services following the acquisition of PowerSecure.
Cost of Other Sales
Cost of other sales increased $223 million and $192 million in 2017 and 2016, respectively. These cost increases were primarily related to work performedsales of products and services by PowerSecure, which was acquired on a generating plant outage, partially offset by decreases in revenues at SouthernLINC Wireless related to lower average per subscriber revenue and fewer subscribers due to continued competition in the industry.May 9, 2016.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other business activities increased $29$7 million, or 30.5%3.6%, in 20152017 as compared to the prior year. The increase was primarily due to a $44 million increase as a result of the inclusion of PowerSecure results for the 12-month period in 2017 compared to eight months in 2016, partially offset by a $35 million decrease in parent company expenses of $27 million related to the proposed Merger partially offset by lower operating expenses at Southern Holdings due to work performed on a generating plant outage in 2014.and the acquisition of PowerSecure. Other operations and maintenance expenses for these other business activities increased $27$70 million, or 39.7%56.5%, in 20142016 as compared to the prior year. The increase was primarily due to $47 million in operations and maintenance expenses following the acquisition of PowerSecure and an increase in parent company expenses of $16 million related to insurance proceeds receivedthe Merger and the acquisition of PowerSecure.
Interest Expense
Interest expense for these other business activities increased $178 million, or 58.4%, in 2013 related2017 as compared to a litigation settlement with MC Asset Recovery, LLC and higher operating expenses at Southern Holdingsthe prior year primarily due to work performed onan increase in average outstanding long-term debt at the parent company. Interest expense for these other business activities increased $239 million, or 362.1%, in 2016 as compared to the prior year primarily due to an increase in outstanding long-term debt at the parent company primarily relating to financing a generating plant outage.portion of the purchase price for the Merger.
Other Income (Expense), Net
Other income (expense), net for these other business activities decreased $18increased $28 million in 20152017 as compared to the prior year. The increase was primarily due to $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. Other income (expense), net for these other business activities decreased $24 million in 2016 as compared to the prior year. The decrease was primarily due to parent company expensesan increase of $14$16 million related to the proposedbridge financing for the Merger. Other
Income Taxes (Benefit)
The income (expense), nettax benefit for these other business activities increased $36$91 million, or 42.1%, in 20142017 as compared to the prior year. The increase wasyear primarily dueas a result of pre-tax earnings (losses) and net tax benefits related to the restructuring of a leveraged lease investment in the first quarter of 2013 and a decrease in charitable contributions in 2014.Tax Reform Legislation. The income tax benefit
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Southern Company has several leveraged lease agreements which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. See Note 1 to the financial statements under "Leveraged Leases" for additional information.
Interest Expense
Interest expense for these other business activities increased $25$84 million, or 61.0%63.6%, in 2015 as compared to the prior year primarily due to an increase in outstanding long-term debt. Interest expense for these other business activities increased $5 million, or 13.9%, in 2014 as compared to 2013 primarily due to an increase in outstanding long-term debt, partially offset by the refinancing of long-term debt at lower rates.
Income Taxes
Income taxes for these other business activities decreased $56 million, or 73.7%, in 2015 as compared to the prior year primarily as a result of state income tax benefits realized in 2015 and changes in pre-tax earnings (losses). Income taxes for these other business activities increased $10 million, or 11.6%, in 20142016 as compared to the prior year primarily as a result of changes in pre-tax earnings (losses)., partially offset by state income tax benefits realized in 2015.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
Effects of Inflation
The traditionalelectric operating companies and natural gas distribution utilities are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company's results of operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The four traditional electric operating companies operate as vertically integrated utilities providing electricityelectric service to customers within their service areasterritories in the Southeast. The seven natural gas distribution utilities provide service to customers in their service territories in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Prices for electricity provided and natural gas distributed to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Prices for wholesale electricity sales and natural gas distribution, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Southern Power continues to focus on long-term capacity contracts.PPAs. See ACCOUNTING POLICIES – "Application"Application of Critical Accounting Policies and Estimates – Electric Utility Regulation"Regulation" herein and Note 3 to the financial statements for additional information about regulatory matters. As discussed further herein, in October 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.
The results of operations for the past three years are not necessarily indicative of Southern Company's future earnings potential. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businessbusinesses of selling electricity.electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the completion and subsequent operation of the Kemper IGCC andnext several years. Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Otherand rate recovery are also major factors includefactors. In addition, the profitability of theSouthern Power's competitive wholesale business and successfully expandingsuccessful additional investments in renewable and other energy projects. projects are also major factors.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements for additional information.
Future earnings for the electricity businessand natural gas businesses will be driven primarily by customer growth. Earnings in the near termelectricity business will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the priceprices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, including the impact of ITCs,tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
affect the business operations, risks, and financial condition of Southern Company. In addition,See Note 12 to the proposed Merger willfinancial statements for additional information regarding Southern Company's recent acquisition and disposition activities.
On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, Southern Company Gas intends to invest less than $0.1 billion in a combined company thatcapital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to various risksthe satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
In addition, Southern Power is pursuing the sale of a 33% equity interest in a newly-formed holding company that do not currently impactowns substantially all of Southern Company.Power's solar assets, which, if successful, is expected to close in the middle of 2018.
The ultimate outcome of these matters cannot be determined at this time.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to federal and statethe transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental statuteslaws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through market-based contracts. Environmental compliance spending overlong-term wholesale agreements for the next several years may differ materially from the amounts estimated. The timing, specific requirements,traditional electric operating companies and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed.Southern Power. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.
Environmental Statutes and Regulations
General
The electric utilities' operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the traditional operating companies had invested approximately $11.4 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $0.9 billion, $1.1 billion, and $0.7 billion for 2015, 2014, and 2013, respectively. The Southern Company system expects that capital expenditures to comply with environmental statutes and regulations will total approximately $1.8 billion from 2016 through 2018, with annual totals of approximately $0.7 billion, $0.5 billion, and $0.6 billion for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates costs associated with closure in place or by other methods, and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
The Southern Company system's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the fuel mix of the electric utilities. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order" and "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions at Alabama Power and Georgia Power, respectively.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the electric utilities' operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the electric utilities' commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.electricity and natural gas.
Air Quality
Compliance withThe Southern Company system's commitment to the Clean Air Act and resulting regulationsenvironment has been demonstrated in many ways, including participating in partnerships resulting in approximately $126 million of funding that has restored or enhanced more than 1.7 million acres of habitat since 2003; the removal of more than 15 million pounds of trash and will continuedebris from waterways through the Renew Our Rivers program; a 21% reduction in surface water withdrawal from 2015 to be a significant focus for2016; reductions in SO2 and NOX air emissions of 95% and 85%, respectively, since 1990; the reduction of mercury air emissions of over 90% since 2005; and the Southern Company system. Additional controls are currently planned or under considerationsystem's changing energy mix.
Through 2017, the traditional electric operating companies have invested approximately $12.9 billion in environmental capital retrofit projects to further reduce air emissions, maintain compliancecomply with existing regulations,environmental requirements, with annual totals of approximately $0.9 billion, $0.5 billion, and meet new requirements.
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In 2012,$0.9 billion for 2017, 2016, and 2015, respectively. Although the EPA finalized the Mercurytiming, requirements, and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury,estimated costs could change as environmental laws and particulate matter on coal-regulations are adopted or modified, as compliance plans are revised or updated, and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensionsas legal challenges to April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each unit withinrules are initiated or completed, the Southern Company system. On June 29, 2015,system's current compliance strategy estimates capital expenditures of $2.8 billion from 2018 through 2022, with annual totals of approximately $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimates do not include any potential compliance costs associated with the U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutantregulation of CO2 emissions from fossil fuel-fired electric generating units. On December 15, 2015,See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates expenditures associated with ash pond closure and ground water monitoring under the U.S. CourtDisposal of Appeals forCoal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the District of Columbia Circuit remanded the MATS ruleCompany's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliance requirementsfinancial statements under "Asset Retirement Obligations and deadlines.Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozonehas set National Ambient Air Quality StandardStandards (NAAQS). for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in 2012. The only area within the traditional operating companies' service territory designated as an ozone nonattainment area for the 2008 standard is a 15-county area within metropolitan Atlanta. On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October 2017.
The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the traditional operating companies' service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated finalplans to complete designations for the 2012 annual standard in December 2014,this rule by no later than April 30, 2018 and no new nonattainment areas were designatedintends to designate an eight-county area within the traditional operating companies' service territory. The EPA has, however, deferred designation decisions for certain areas in Florida and Georgia.
Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010.metropolitan Atlanta as nonattainment. No other areas within the Southern Company system's electric service territory have been or are anticipated to be designated as nonattainment under this rule. However,the 2015 ozone NAAQS. In 2010, the EPA has finalized a data requirements rule to support additional designation decisionsrevised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the future, which could result in nonattainment designations for areas within thevicinity of Southern Company system's service territory. Implementation of the revisedsystem-owned SO2 standard could require additional reductions insources have been designated nonattainment under the 2010 one-hour SO2 emissionsNAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance and operational costs.costs could result.
In February 2014,2011, the EPA proposed to delete fromfinalized the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units owned by Alabama Power, units co-owned with Mississippi Power, and units owned by SEGCO, which is jointly owned by Alabama Power and Georgia Power.
Each of the states in which the Southern Company system has fossil generation is subject to the requirements of the Cross StateCross-State Air Pollution Rule (CSAPR). and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that limitsaddresses the impacts of the interstate transport of SO2 and nitrogen oxideNOX emissions from fossil fuel-fired power plants located in 28upwind states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,the eastern half of the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number ofon air quality in downwind states. The Southern Company system has fossil fuel-fired generation in several states including Alabama, Florida, Georgia, North Carolina, and Texas, but rejected all other pending challengessubject to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,these requirements. In October 2016, the EPA published a proposed revision tofinal rule that revised the CSAPR that would revise existing ozone-seasonseasonal NOX program, establishing more stringent NOX emissions budgets for nitrogen oxide in Alabama, and Mississippi, and would remove FloridaTexas. The EPA also removed North Carolina from the CSAPR NOX seasonal program and completely removed Florida from all CSAPR programs. Georgia's seasonal NOX budget remains unchanged. The outcome of ongoing CSAPR litigation, to which Mississippi Power is a party, could have an impact on the State of Mississippi's allowance allocations under the CSAPR seasonal NOXprogram. The EPA proposes to finalize this rulemaking by summer 2016.Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for Southern Company.
The EPA finalized regional haze regulations in 2005 with aand 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, (primarilyincluding national parks and wilderness areas)areas. States must submit a revised state implementation plan (SIP) to the EPA by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieveJuly 31, 2021, demonstrating reasonable progress toward the naturaltowards achieving visibility conditions goal by 2018 and for each 10-year period thereafter.improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs
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Southern Company and Subsidiary Companies 2015 Annual Report
(including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and Texas) to revise or remove the provisions of their SIPs relating to the regulation ofregulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM) by no later than November 22, 2016.
. The Southern Company system has developedstate excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the currentif removed, could affect unit availability and proposed environmental requirements discussed above. As part of this strategy, certain of the traditional operating companies have developed a compliance planresult in increased operations and maintenance costs for the MATS rule which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, the Alabama opacity rule, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on the Southern Company system cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs aresystem. The EPA has not recovered through regulated rates or through PPAs.
In additionyet responded to the federal air quality laws described above, Georgia Power has also been subject toSIP revisions proposed by states within the requirements of the 2007 State of Georgia Multi-Pollutant Rule. The Multi-Pollutant Rule and a companion rule required reductions in emissions of mercury, SO2, and nitrogen oxide state-wide through the installation of specified control technologies and a 95% reduction in SO2 emissions at certain coal-fired generating units by specific dates between 2008 and 2015. In 2015, Georgia Power completed implementation of the measures necessary to comply with the Georgia Multi-Pollutant Rule at all 16 of its coal-fired generating units required to be controlled under the rule.Southern Company system's traditional electric service territory.
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existingIn 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014.order to minimize their effects on fish and other aquatic life. The effect of this final rule will dependregulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the results of additional studies and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.
On November 3, 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and implementation of the final rule and cannot be determined at this time.
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the traditional electric operating companies' coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020.
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission, distribution, and pipeline projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
Coal Combustion Residuals
The traditional operating companies currently manage CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at 22 electric generating plants. In addition to on-site storage, the traditional operating companies also sell a portion of their CCR to third parties for beneficial reuse. Individual states regulate CCR and the states in the Southern Company system's service territory each have their own regulatory requirements. Each traditional operating company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.
On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulatesfinalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Unitslandfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule does not automatically require closurerequires CCR units to be evaluated against a set of CCR Units but includesperformance criteria and potentially closed if minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansionsare not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.
The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule. The Georgia Department of Natural Resources has incorporated the requirements of the CCR Rule into its solid waste regulations, which established additional requirements for all of Georgia Power's CCR units, and active landfills. Failure to meethas requested that the minimum criteria can resultEPA approve its state permitting program. The other states in the required closure of a CCR Unit. AlthoughSouthern Company system's electric service territory have not yet submitted plans to the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA's final rule continues to exclude the beneficial use of CCR from regulation.EPA.
Based on initial cost estimates for closure in place or by other methods, and groundwater monitoring of ash ponds pursuant to the CCR Rule, Southern Company recorded incremental AROs related to thefor each CCR Rule.unit in 2015. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the traditional electric operating companies expect towill continue to periodically update these estimates. The traditional operating companies are currently completing an analysis of the plan of closure for all ash ponds in the Southern Company system, including the timing of closurecost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and related cost recovery through regulated rates subject to the traditional operating companies' respective state PSC approval. Based on the results of that analysis, the traditional operating companies may accelerate the timing of some ash pond closures which could increase their ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule cannot be determined at this timeContractual Obligations" herein and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset"Asset Retirement Obligations and Other Costs of Removal"Removal" for additional information regarding Southern Company's AROs as of December 31, 2015.2017.
Environmental Remediation
The Southern Company system must comply with other environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company Gas conduct studies to determine the extent of any required cleanup and theSouthern Company has recognized in its financial statements the estimated costs to clean up known impacted sites.sites in its financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have eachall received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These ratesregulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs.PSCs or other applicable state regulatory agencies. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.
Global Climate Issues
On October 23, 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stay will remain in effect through the resolution of the litigation, whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit or the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Company's results of operations, cash
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
flows,that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.
Global Climate Issues
In 2015, the EPA published final rules limiting CO2 emissions from new, modified, and financial condition could be significantly impacted if such costs are not recovered through regulated ratesreconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or through PPAs. However,CPP). In February 2016, the ultimate financial and operational impactU.S. Supreme Court granted a stay of the final rules onCPP, which will remain in effect through the Southern Company system cannot be determined at this timeresolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and will depend upon numerous factors,any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including the Southern Company system's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, including legal challenges filed byproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the traditional operating companies; individual state implementation of the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countriescountries.
Domestic GHG policies may emerge in the future requiring the United States to transition to a lower GHG emitting economy. The Southern Company system has transitioned from an electric generating mix of 71% coal and cannot be determined at this time.
The EPA's greenhouse11% natural gas reporting rule requires annual reportingin 2005 to 30% percent coal and 46% natural gas mix in 2017 and currently includes over 8,000 MWs of CO2 equivalent emissionsrenewable projects. In addition, the Southern Company system has retired 4,226 MWs of coal- and oil-fired generating capacity since 2010 and converted 3,280 MWs of generating capacity from coal to natural gas since 2015. Southern Company Gas replaced 5,300 miles of bare steel and cast-iron pipe, resulting in removal of 2.5 million metric tons for a company's operational control of facilities.GHG from its natural gas distribution system since 1998. Based on ownership or financial control of facilities, the Southern Company system's 2014 greenhouse gas2016 GHG emissions were approximately 112 million metric tons of CO(CO2 equivalent. Theequivalent) were approximately 99 million metric tons, with 2017 emissions estimated at 96 million metric tons. This equates to a reduction of 27% between 2005 and 2016 and a preliminary estimate of 30% through 2017. To better represent GHG emission reductions, the Southern Company system's 2015 greenhouse gas emissions onsystem is transitioning to a maximum emission baseline year of 2007 and a baseline calculation methodology consistent with the sameEPA's Greenhouse Gas Reporting Program methodology. On a preliminary basis, is approximately 101 million metric tonsthese baseline adjustments result in an estimated GHG emission reduction of CO2 equivalent. The level of greenhouse gas emissions36% from year to year will depend on the level of generation, the mix of fuel sources, and other factors.2007 through 2017.
FERC Matters
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
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Southern Company and Subsidiary Companies 2017 Annual Report
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Retail Southern Company Gas
At December 31, 2017, Southern Company Gas' midstream operations business was involved in two gas pipeline construction projects, the Atlantic Coast Pipeline project and the PennEast Pipeline project, which received FERC approval in October 2017 and January 2018, respectively. Southern Company Gas' portion of the expected capital expenditures for these projects total approximately $586 million. These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served.
On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced. See Note 4 to the financial statements for additional information.
Regulatory Matters
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements under "Retail "Regulatory Matters – Alabama Power"Power" for additional information regarding Alabama Power's rate mechanisms and accounting orders.
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, customer refundsthe excess will be required;refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On November 30, 2015,December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for 2016.calendar year 2018. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.2018.
In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service under Rate CNP.service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate
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Southern Company and Subsidiary Companies 20152017 Annual Report
Rate CNP PPA. On March 3, 2015, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 20152017 through March 31, 2016.2018. No adjustment to Rate CNP PPA is expected in 2016.2018.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
Rate CNP Environmental allowedCompliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.
On November 30, 2015, Alabama Power made its annual Revenues for Rate CNP Compliance, submission toas recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its cost of complying with governmental mandates for cost year 2016.under recovered balance in Rate CNP Compliance increased 4.5%, or approximately $250 million annually,to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2016.2017.
On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing.
Environmental Accounting Order
Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are beingThe regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See "Environmental"Environmental Matters – Environmental StatutesLaws and Regulations"Regulations" herein for additional information regarding environmental regulations.
In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.
In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.
Cost of Removal Accounting Order
In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs previously deferred were fully amortized in December 2014.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs on certified project costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariffs.tariff. See Note 3 to the financial statements under "Retail "Regulatory Matters – Georgia Power"Power" for additional information.
Rate Plans
II-29Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers. See Note 3 to the financial
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Southern Company and Subsidiary Companies 20152017 Annual Report
statements under "Regulatory Matters – Georgia Power – Rate Plans
In 2013, the Georgia PSC voted to approve" for additional information regarding the 2013 ARP. The 2013 ARP reflectsand Note 12 to the settlement agreement among Georgia Power,financial statements under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors.Merger.
On December 16, 2015, inIn accordance with the 2013 ARP, the Georgia PSC approved an increaseincreases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014,2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $11$44 million in 2016,2018, as approved by the Georgia PSC on February 18, 2016.January 16, 2018. In 2015,2017, Georgia Power's retail ROE was within the allowed retail ROE range.range, subject to review and approval by the Georgia PSC.
On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to file a general base rate casesubmit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by July 1, 2016, in response to which the Georgia PSC wouldMarch 6, 2018. The ultimate outcome of this matter cannot be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.determined at this time.
Integrated Resource Plan
See "Environmental Matters" and "Rate Plans""Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent limitations guidelinesELG for steam electric power plants and additional regulations of CCR and CO2; the State of Georgia's Multi-Pollutant Rule; and Georgia Power's analysis of the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations..
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.
In the 2013 ARP,July 2016, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.
On January 29, 2016, Georgia Power filed itsPower's triennial IRPIntegrated Resource Plan (2016 IRP). The filing included a request to decertify including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval, as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, IRP. The 2016 IRP also reflects thatthe Plant Mitchell and Plant Kraft units were retired and Georgia Power exercised its contractual option to sellsold its 33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 toLLC.
Additionally, the financial statements for additional information.
InGeorgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia Power requestedPSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. Georgia Power also requested that the Georgia PSC approve the deferral of the costand costs associated with materials and supplies remaining at the unit retirement datesdate to a regulatory asset, to be amortized over a period deemed appropriate byasset. Recovery of the Georgia PSC.
The decertification and retirement of these units are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's ordersunit's net book value will continue through December 31, 2019, as provided in the 2016 IRP2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and next generalcosts associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
Additionally,The Georgia PSC also approved the 2016 IRP included a Renewable Energy Development Initiative requesting(REDI) to procure up to 525an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to expandbe in operation by the end of 2019. Georgia Power's existing renewable initiatives, includingPower also filed for and received approval to develop several solar generation projects to fulfill the Advanced Solar Initiative (ASI).approved self-build capacity.
A decision fromIn the 2016 IRP, the Georgia PSC onalso approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the 2016 IRPGeorgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the third quarter 2016.2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The ultimate outcome ofincremental restoration costs related to these matters cannot be determined at this time.hurricanes deferred in Georgia Power's regulatory
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Southern Company and Subsidiary Companies 20152017 Annual Report
Renewables
On September 16, 2015,asset for storm damage totaled approximately $260 million. At December 31, 2017, the Alabama PSC approved Alabama Power's petition for a Renewable Generation Certificate for up to 500 MWs. This will allow Alabama Power to build its own renewable projects, each less than 80 MWs, or purchase power from other renewable-generated sources.
In May 2014, the Georgia PSC approvedtotal balance in Georgia Power's application for the certificationregulatory asset related to storm damage was $333 million. The rate of two PPAs executed in 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
Asstorm damage cost recovery is expected to be adjusted as part of the Georgia Power ASI, Georgia Power executed ten PPAs that were approvedPower's next base rate case required to be filed by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. Two PPAs began in December 2015 and eight are expected to begin in December 2016, all of which have terms ranging from 20 to 30 years.July 1, 2019. As a result of certain acquisitions bythis regulatory treatment, costs related to storms are not expected to have a material impact on Southern Power, Company's financial statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.
In October 2014, the Georgia PSC approved – Storm Damage Recovery" for additional information regarding Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. One of the three solar generation facilities began commercial operation on December 31, 2015. In addition, in December 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate a 30-MW solar generation facility at Kings Bay Naval facility. On July 21, 2015, the Georgia PSC approved Georgia Power's request to build and operate an up to 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia. Georgiastorm damage reserve.
Gulf Power subsequently determined that a 31-MW facility will be constructed on the site. On December 22, 2015, the Georgia PSC approved Georgia Power's request to build and operate the remaining 15 MWs at a separate facility on the Fort Stewart Army base in Hinesville, Georgia. These facilities are expected to be operational by the end of 2016.
On April 7, 2015,4, 2017, the GeorgiaFlorida PSC approved the consolidation2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of four PPAs eachthe 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the same counterparty into twofirst billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new PPAsdepreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with new biomass facilities.the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the order,2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the total 116 MWs from the existing four PPAs provided the capacityrevenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for two new PPAs of 58 MWs each. The new PPAs were executed on June 15, 2015 and November 23, 2015 and will beginprospective application in June 2017. See "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" herein for additional information on Georgia Power's renewables activities.
On April 16, 2015,a change to base rates in a limited scope proceeding before the Florida PSC approved three energy purchase agreements totaling 120 MWsPSC. In lieu of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these solar agreements are expectedthis approach, on February 14, 2018, the parties to begin by early 2017. On May 5, 2015,the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSCPSC. If approved, an energy purchase agreementthe 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for upa one-time refund of $69.4 million for the retail portion of unprotected (not subject to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements began in January 2016, are for energy only, and will be recoverednormalization) deferred tax liabilities through Gulf Power's fuel cost recovery mechanism.rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
On November 10, 2015, the Mississippi PSC issued three separate orders approving three solar facilities for a combined total of approximately 105 MWs.February 7, 2018, Mississippi Power will purchase allrevised its annual projected PEP filing for 2018 to reflect the impacts of the energy producedTax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its
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Southern Company and Subsidiary Companies 2017 Annual Report
distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the solar facilitiesGeorgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the 25-year termbilling factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the contractsnatural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under three PPAs, twothese programs for 2018 is $395 million.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which have been finalized and one of which remains under negotiation. The projects are expectedNicor Gas expects to be in servicefile by the end of 2016 and the resulting energy purchasessecond quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
The ultimate outcome of these matters cannot be recovered through Mississippi Power's fuel cost recovery mechanism.determined at this time.
See Note 12 to the financial statements for information on Southern Power's renewables activities.
Retail Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary. During 2015, each of the traditional operating companies filed requests with their respective state PSCs for fuel rate decreases. Upon approval of these requests, each of the traditional operating companies decreased fuel rates in January 2016.
See Note 1 to the financial statements under "Revenues""Revenues" and Note 3 to the financial statements under "Retail "Regulatory Matters – Alabama Power – Rate ECR"ECR" and "Retail "Regulatory Matters – Georgia Power – Fuel Cost Recovery"Recovery" for additional information.
Kemper County Energy Facility
II-31The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural
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Southern Company and Subsidiary Companies 20152017 Annual Report
gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The Kemper Settlement Order established the Kemper Settlement Docket for the purposes of pursuing a global settlement of the related costs.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2017.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the
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Southern Company and Subsidiary Companies 2017 Annual Report
plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop and other related parties and the arbitration was dismissed.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, as well as adding or changing fuel sources forenvironmental modifications to certain existing units, adding environmental control equipment,expanding the electric transmission and distribution systems, and updating and expanding the transmission andnatural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. The constructionSouthern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the traditional operating companiesnatural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. The Southern Power areCompany system's construction program is currently estimated to include an investment oftotal approximately $7.3$9.4 billion, $5.2$9.3 billion, $8.4 billion, $7.0 billion, and $5.5$6.9 billion for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively.
The two largest construction projectsproject currently underway in the Southern Company system areis Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's Kemper IGCC.. See Note 3 to the financial statements under "Retail Regulatory Matters – Georgia Power – "Nuclear Construction" and "Integrated Coal Gasification Combined Cycle"Construction" for additional information. ForSee Note 12 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, seefacilities. See Note 123 to the financial statements under "Southern Power"Regulatory Matters – Construction Projects.Southern Company Gas – Regulatory Infrastructure Programs" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital"Capital Requirements and Contractual Obligations"Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Integrated Coal Gasification Combined CycleNuclear Construction
Mississippi Power's current cost estimateVogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Kemper IGCCVogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in totalOctober 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $6.63$1.6 billion which includesof financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $5.29$50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs subject to the construction cost cap. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. In the aggregate, the Company has incurred charges of $2.41 billion ($1.5 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2015. Mississippi Power's current cost estimate includes costs through August 31, 2016. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants2015 and excluding the Cost Cap Exceptions, will be reflected in the Company's statementsfourteenth VCM report should be disallowed from rate base on the basis of incomeimprudence; (ii) the Contractor Settlement Agreement was reasonable and these changes could be material.
During 2015, events relatedprudent and none of the amounts paid pursuant to the Kemper IGCC hadContractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a significant adverserevised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on Mississippi Power's financial condition. These events include (i)cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the terminationROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by SMEPA in May 2015 of the APA between Mississippi Power and SMEPA, whereby SMEPA previously agreed to purchase a 15% undivided interestGeorgia PSC in the Kemper IGCC,2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and Mississippi(c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's subsequent returnaverage cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $301 million, including interest, to SMEPA; (ii) the termination of Mirror CWIP rates in July 2015 and the refund of $371$120 million in Mirror CWIP rate collections, including carrying costs, in2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the fourth quarter 2015 as a result of the Mississippi Supreme Court's reversal of the Mississippi PSC's 2013 rate order authorizing the collection of $156 million annually in Mirror CWIP rates;Georgia PSC stated if other certain conditions and (iii) the required recapture in December 2015 of $235 million of Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 48A (Phase II) tax credits as a result of the extension of the expected in-service date for the Kemper IGCC.
As a result of the termination of the Mirror CWIP rates, Mississippi Power submitted a filing to the Mississippi PSC requesting interim rates to collect approximately $159 million annually until a final rate decision could be made on Mississippiassumptions upon which Georgia Power's request to recover costs associated with Kemper IGCC assets that had been placed in service. The Mississippi PSC approved the implementation of the requested interim rates in August 2015. Subsequently, on December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order),seventeenth VCM report are based on a stipulation between Mississippido not materialize, both Georgia Power and the MPUS, authorizing Mississippi PowerGeorgia PSC reserve the right to replacereconsider the interim rates with rates that provide for the recovery of approximately $126 million annually relateddecision to Kemper IGCC assets previously placed in service. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected in the third quarter 2016. continue construction.
On February 25, 2016, Greenleaf CO2 Solutions, LLC12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a notice of appeal ofpetition appealing the In-Service Asset Rate OrderGeorgia PSC's January 11, 2018 order with the Mississippi SupremeFulton County Superior Court. MississippiGeorgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations.operations, financial condition, and liquidity.
The ultimate outcomeIRS allocated PTCs to each of these matters cannotPlant Vogtle Units 3 and 4, which originally required the applicable unit to be determined at this time.placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Nuclear Construction
On December 31, 2015, Westinghouse Electric Company LLC (Westinghouse) andIn its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power Oglethorpe Power Corporation, the Municipal Electric Authorityexpects to file its eighteenth VCM report on February 28, 2018 requesting approval of Georgia, and the Cityapproximately $450 million of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and Westinghouse and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor)construction capital costs (before payments received under the engineering, procurement, and construction agreement between the Vogtle Owners and the Contractor (Vogtle 3 and 4 Agreement), including the pending litigation between the Vogtle Owners and the Contractor (Vogtle Construction Litigation).
Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The ContractorGuarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commenceCustomer Refunds) incurred from the current estimated nuclear fuel loading date for each unit, which isJuly 1, 2017 through December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in2017. Georgia Power's previously disclosed in-service cost estimate.
Further, as part of the settlement: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction ofCWIP balance for Plant Vogtle Units 3 and 4 that occurred onwas approximately $4.8 billion as of December 31, 2017, or before$3.3 billion net of payments received under the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
On January 21, 2016, Georgia Power submitted the ContractorGuarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following Georgia Power's filing under the order, the Georgia PSC Staff (Staff) will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors. The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations.Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax MattersCost and Schedule
Bonus Depreciation
On December 18, 2015,Georgia Power's approximate proportionate share of the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placedremaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service overdates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the next five years. The PATH Act allowsGuarantee Settlement Agreement and the Customer Refunds.
Georgia Power estimates that its financing costs for 50% bonus depreciation for 2015, 2016,construction of Plant Vogtle Units 3 and 2017; 40% bonus depreciation for 2018;4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and 30% bonus depreciation for 2019vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain long-lived assets placed in service in 2020. The extensionlicense amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of 50% bonus depreciation is expected toInspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in approximately $855 million of positive cash flows foradditional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the 2015 tax year and approximately $1.3 billion for the 2016 tax year, which may not all be realizedproject schedule that could result in 2016 due to a projected net operating loss for the 2016 tax year. Approximately $360 million of this benefit is dependent upon placing the remainder of the Kemper IGCC in service in 2016. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. increased costs.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Other Matters
II-33As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down by 20% each year until completely phased out for qualified property placed in service after December 31, 2027. Further, the business interest deduction is limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforwards, and depreciation and amortization through December 31, 2021, and thereafter to 30% of taxable income excluding interest and NOL carryforwards.
Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of the consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $264 million, a $0.4 billion decrease in regulatory assets, and a $6.9 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities. Also, the OCI ending balance at December 31, 2017 includes $30 million of stranded excess deferred tax balances, which will be adjusted through retained earnings in subsequent periods.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. On January 31, 2018, SCS, on behalf of the traditional electric operating companies, filed with the FERC a reduction to the open access transmission tariff charge for 2018 to reflect the revised federal corporate income tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the traditional electric operating companies' and the natural gas distribution utilities' rate filings to reflect the impacts of the Tax Reform Legislation.
On February 9, 2018, the Bipartisan Budget Act of 2018 was signed into law. Included in the tax extenders portion of the law were provisions extending PTCs on advanced nuclear power facilities and ITCs on qualified fuel cells. A subsidiary of PowerSecure installed fuel cells in 2017 which are expected to qualify for approximately $80 million of ITCs; however, the impact of the related tax benefits would be substantially offset by additional required payments under the applicable purchase contracts. Should Southern Company have a NOL in 2018, all of these ITCs may not be fully realized in 2018. See Note 3 to the financial statements under "Nuclear Construction" for additional information on the PTCs relating to advanced nuclear power facilities.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $870 million for the 2017 tax year and approximately $290 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes – Net Operating Loss," respectively, for additional information. The ultimate outcome of these matters cannot be determined at this time.
Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection withTax Reform Legislation retained the Kemper IGCC. These tax creditsrenewable energy incentives that were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II credits have been recaptured. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information.
In 2009, President Obama signed into law the American Recovery and Reinvestment Act of 2009 (ARRA). Major tax incentivesincluded in the ARRA included renewable energy incentives.PATH Act. The PATH Act extended the ITC with a phase out that allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and thea permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act extended the production tax credit (PTC) for wind projects with a phase out that allows for 100% PTC for wind projects that commencecommenced construction in 2016; 80% PTC for wind projects that commencecommenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits amortized and the tax benefit related to basis differences.
Section 174 ResearchSouthern Power
In September 2017, Southern Power began a legal entity reorganization of various direct and Experimental Deduction
Southern Company reflected deductions for researchindirect subsidiaries that own and experimental (R&E) expendituresoperate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the Kemper IGCCfirst quarter 2018. Southern Power is pursuing the sale of a 33% equity interest in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated withnewly-formed holding company owning these R&E deductions totaling approximately $423 million as of December 31, 2015. See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. Also see "Bonus Depreciation" herein.solar assets. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiariesor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Through 2015, capacity revenues representedIn 2016, the majoritySEC began conducting a formal investigation of Gulf Power's wholesale earnings. GulfSouthern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had long-term sales contracts to cover 100%concluded its investigation with no recommended enforcement action.
Litigation
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its ownership share of Plant Scherer Unit 3 (205 MWs)officers, and these capacity revenues represented 82% of Gulf Power's total wholesale capacity revenues for 2015. Due tocertain former Mississippi Power officers in the expiration of a wholesale contract at the end of 2015 and future expiration dates of the remaining wholesale contractsU.S. District Court for the unit, Gulf Power currently has contracts to cover 34%Northern District of the unit for 2016 and 27%Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of the unit through 2019. Gulf Power is actively evaluating alternatives relating to this asset, including replacement wholesale contracts. The expirationall persons who purchased shares of the contract in 2015 and the scheduled future expiration of the remaining contracts are not expected to have a material impact on Southern Company's earnings. In the event some portion of the Gulf Power's ownership of Plant Scherer Unit 3 is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into thecommon stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, power pool or intocertain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the wholesale market.Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The ultimate outcome of this matter cannot be determined at this time.complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Investments in Leveraged Leases
A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
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Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 94%86% of Southern Company's total operating revenues for 2015,2017, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies;companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper IGCC Estimated Construction Costs, Project Completion Date, andCounty Energy Facility Rate Recovery
During 2015,For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.4 billion ($1.5 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2015.related
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
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Southern Company and Subsidiary Companies 20152017 Annual Report
Mississippi Power's revised cost estimate includes costs through August 31, 2016. Any extensionto the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the in-service date beyond August 31, 2016 is currently estimatedMississippi PSC's June 21, 2017 stated intent to result in additional base costs of approximately $25 millionissue an order (which occurred on July 6, 2017) directing Mississippi Power to $35 million per month,pursue a settlement under which includes maintaining necessary levels of start-up labor, materials, and fuel,the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extensionMississippi Power's June 28, 2017 suspension of the in-service date with respect tooperation and start-up of the gasifier portion of the Kemper IGCC beyond August 31, 2016 would alsoCounty energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase costs for the Cost Cap Exceptions,Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which are not subjectincluded estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the $2.88 billion cost cap established bysuspension period prior to conclusion of the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month,Kemper Settlement Docket, as well as carrying costsa charge of $78 million associated with the Kemper Settlement Agreement.
In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 14 to the financial statements for additional information on the individual charges by quarter.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and operating expensesno longer represents a critical accounting estimate.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on Kemper IGCCa stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets placedare estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in servicefuture years. The apportionments and consulting and legal fees of approximately $2 million per month.methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on Southern Company's financial statements.
Given the significant judgment involved in estimating the future costs to complete constructionNOL and start-up, the project completion date, the ultimate rate recoverytax credit carryforwards and multi-state apportionments for the Kemper IGCC, and the potential impact on Southern Company's results of operations,all subsidiaries, Southern Company considers these itemsstate deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See NoteFUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Integrated Coal Gasification Combined Cycle""Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2 – and facilities that are subject to the CCR Rule, principally ash ponds.2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore,as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
As a result of the final CCR Rule discussed above, Alabama Power, Gulf Power, and Mississippi Power recorded newThe cost estimates for AROs for facilities that are subjectrelated to the CCR Rule. Georgia Power had previously recorded AROs as a resultdisposal of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place or by other methods.closure. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the traditional electric operating companies expect towill continue to periodically update these estimates.cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
Pension and Other Postretirement Benefits
Southern Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ForBeginning in 2016, Southern Company has adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost
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Southern Company and Subsidiary Companies 2017 Annual Report
component of net periodic pension and other postretirement benefit plan expense will decreasedecreased by approximately $96 million in 2016.
The following table illustrates the sensitivity to changes in Southern Company's long-term assumptions with respect to the assumed discount rate, the assumed salaries, and the assumed long-term rate of return on plan assets:
|
| | | | | |
Change in Assumption | Increase/(Decrease) in Total Benefit Expense for 20162018 | | Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 20152017 | | Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 20152017 |
| (in millions) |
25 basis point change in discount rate | $30/40/$(29)(38) | | $353/504/$(335)(476) | | $56/68/$(53)(65) |
25 basis point change in salaries | $12/24/$(11)(23) | | $91/119/$(88)(115) | | $–/$– |
25 basis point change in long-term return on plan assets | $25/33/$(25)(33) | | N/A | | N/A |
N/A – Not applicable
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Goodwill and Other Intangible Assets
The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.3 billion at December 31, 2017.
Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power's acquisitions, other intangible assets, net of amortization totaled approximately $873 million at December 31, 2017.
The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.
See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding Southern Company's goodwill and other intangible assets and Note 12 to the financial statements for additional information related to Southern Company's recent acquisitions and proposed dispositions.
Derivatives and Hedging Activities
Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.
Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative
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Southern Company and Subsidiary Companies 2017 Annual Report
instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:
the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the impact of Southern Company's nonperformance risk on its liabilities.
Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.
Contingent Obligations
Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers revises(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.
Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. Southern Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606. The ultimate impact606 did not result in a cumulative-effect adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Leases
On April 7, 2015,In February 2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance CostsLeases (Topic 842) (ASU 2015-03)2016-02). ASU 2015-032016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015. As permitted,2018 and Southern Company elected to earlywill adopt the guidancenew standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as ofrestricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 31, 201515, 2017, and will be applied its provisions retrospectively to each prior period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for comparative purposes. The new guidance resulted in an adjustment tocapitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of debt issuancethe service cost component and the other components of net periodic pension and postretirement benefit costs asin the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an offsetincrease in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related debt balances primarily in long-term debt totaling $202 million as ofpresentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 31, 2014. These debt issuance costs were previously presented within unamortized debt issuance expense. Other than the reclassification, the15, 2018, with early adoption ofpermitted. Southern Company adopted ASU 2015-03 did not have an2017-12 effective January 1, 2018 with no material impact on the results of operations, cash flows, orits financial condition of Southern Company. See Notes 6 and 10 to the financial statements for disclosures impacted by ASU 2015-03.statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 2 and 10 to the financial statements for disclosures impacted by ASU 2015-07.
On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million, with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of Southern Company. See Note 5 to the financial statements for disclosures impacted by ASU 2015-17.
FINANCIAL CONDITION AND LIQUIDITY
Overview
Earnings in 2015 and 2014all periods presented were negatively affected by revisions to the cost estimate forcharges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, 2015 and December 31, 2014. Through December 31, 2015,2017.
The Southern Company has incurred non-recoverable cash expenditures of $1.95 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
Southern Company'ssystem's cash requirements primarily consist of funding ongoing operations, funding the cash consideration for the Merger, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system's cash needs. For the three-year period from 20162018 through 2018,2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Southern Company system's projected capital expenditures in that period include investments to build new generation facilities, to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" and "Sources"Sources of Capital," "Financing"Financing Activities," and "Capital"Capital Requirements and Contractual Obligations"Obligations" herein for additional information.
Southern Company's investments in the qualified pension planplans and the nuclear decommissioning trust funds decreasedincreased in value as of December 31, 20152017 as compared to December 31, 2014.2016. No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension planplans are anticipated during 2016.2018. See "Contractual Obligations""Contractual Obligations" herein and Notes 1 and 2 to the financial statements under "Nuclear Decommissioning""Nuclear Decommissioning" and "Pension"Pension Plans," respectively, for additional information.
Net cash provided from operating activities in 20152017 totaled $6.3$6.4 billion, an increase of $459 million$1.5 billion from 2014.2016. The increase in net cash provided from operating activities was primarily due to an increaseincreases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in fuel cost recovery,2016, partially offset by the timing of vendor payments. Net cash provided from operating activities in 20142016 totaled $5.8$4.9 billion, a decrease of $282 million$1.4 billion from 2013.2015. Significant changes in operating cash flow for 20142016 as compared to 20132015 included $500 millionapproximately $1.0 billion of voluntary contributions to the qualified pension plan in 2016 and ana $1.2 billion increase in receivables due to under recovered fuel costs, partially offset by an increase in accrued compensation.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Companyunutilized ITCs and Subsidiary Companies 2015 Annual ReportPTCs.
Net cash used for investing activities in 2017, 2016, and 2015 2014, and 2013 totaled $7.3$7.2 billion, $6.4$20.0 billion, and $5.7$7.3 billion, respectively. The cash used for investing activities in each of these years2017 was primarily due to gross property additions forthe traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 was primarily due to the traditional electric operating companies' gross property additions for installation of equipment at electric generating facilities to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Power's acquisitions of solar facilities, and purchases of nuclear fuel.
Net cash provided from financing activities totaled $1.0 billion in 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries' continuous construction programs, Southern Power's acquisitions, and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Net cash provided from financing activities totaled $1.7 billion in 2015 primarily due to issuances of long-term debt and common stock and an increase in short-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Net cash provided from financing activities totaled $644 million in 2014 due to issuances of long-term debt and common stock, partially offset by common stock dividend payments, redemptions of long-term debt, and a reduction in short-term debt. Net cash used for financing activities totaled $324 million in 2013 due to redemptions of long-term debt and payments of common stock dividends, partially offset by issuances of long-term debt and common stock and an increase in notes payable. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes in 20152017 included increasesdecreases of $4.9$7.3 billion and $0.8 billion in plant in service, netaccumulated deferred income taxes and deferred charges related to income taxes, respectively, and an increase of depreciation and $1.3$7.0 billion in construction workdeferred credits related to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
income taxes primarily resulting from the impacts of the Tax Reform Legislation; an increase of $1.4 billion in progress fortotal property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities; increases of $0.7facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.8 billion in other regulatory assets, deferred and $1.6 billion in AROs primarily resulting from impactswrite-down of the CCR Rule;gasification portions of the Kemper County energy facility and payments of $1.7 billion received by Georgia Power under the Guarantee Settlement Agreement; an increase of $3.4$3.1 billion in short-term and long-term debt (including amounts due within one year) primarily to fund the subsidiaries'Southern Company system's continuous construction programs and for other general corporate purposes; and an increasea decrease of $1.2$1.1 billion in accumulated deferred income taxestotal stockholder's equity primarily as a resultrelated to the Kemper County energy facility charges, partially offset by the issuance of bonus depreciation.additional shares of common stock. See Note 1FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" and "Financing Activities" herein and Note 53 to the financial statements under "Nuclear Construction" and "Kemper County Energy Facility" for additional information regarding AROs and deferred income taxes, respectively.information.
At the end of 2015,2017, the market price of Southern Company's common stock was $46.79$48.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.59$23.99 per share, representing a market-to-book value ratio of 207%201%, compared to $49.11, $21.98,$49.19, $25.00, and 223%197%, respectively, at the end of 2014.2016.
Southern Company's consolidated ratio of common equity to total capitalization plus short-term debt was 31.5% and 33.3% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-termborrowings from financial institutions, and debt term loans, and external security issuances.equity issuances in the capital markets. Equity capital can be provided from any combination of the Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2016,2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from any potential sale of a 33% equity interest in a newly-formed holding company that owns substantially all of its solar assets, if completed. Southern Company Gas also plans to utilize the proceeds from the pending asset sales of two of its natural gas distribution utilities. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
In addition, in 2014, Georgia Power may make borrowings through a loan guarantee agreement (Loanentered into the Loan Guarantee Agreement), between Georgia Power andAgreement with the DOE, under which the proceeds of whichborrowings may be used to reimburse Georgia Power for a portionEligible Project Costs incurred in connection with its construction of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs).4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of December 31, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE"DOE Loan Guarantee Borrowings"Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Retail Regulatory Matters – Georgia Power – "Nuclear Construction"Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Eligible Project Costs incurred through December 31, 2015 would allow for borrowings of up to $2.3 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.2 billion.
Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for the commercial operation of the Kemper IGCC. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
Mississippi Power expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.
The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC.PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system.
In addition, Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
As of December 31, 2015,2017, Southern Company's current liabilities exceeded current assets by $2.6$3.5 billion, primarily due to $3.9 billion of long-term debt that is due within one year (comprised of $2.7approximately $1.0 billion includingat the parent company, $0.9 billion at Georgia Power, $1.0 billion at Mississippi Power, $0.8 billion at Southern Power, and $0.2 billion at Southern Company Gas) and $2.4 billion of notes payable (comprised of approximately $0.5$0.6 billion at the parent company, $0.2 billion at Alabama Power, $0.7 billion at Georgia Power, $0.1 billion at Gulf Power, $0.7 billion at MississippiSouthern Power, and $0.4$1.5 billion at Southern Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016.Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Power,Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
The financial condition of Mississippi Power and its ability to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of approximately $371 million of Mirror CWIP rate collections, including associated carrying costs, the termination of the Mirror CWIP rate, and the required recapture of Phase II tax credits. On December 3, 2015, the Mississippi PSC approved the In-Service Asset Rate Order which, among other things, provides for retail rate recovery of an annual revenue requirement of approximately $126 million which became effective on December 17, 2015. Mississippi Power plans to refinance its 2016 debt maturities with bank term loans and to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
At December 31, 2015,2017, Southern Company and its subsidiaries had approximately $1.4$2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 20152017 were as follows:
| | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2016 | | 2017 | | 2018 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2018 |
| 2019 |
| 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
Southern Company (a) | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 40 |
| | — |
| | 500 |
| | 800 |
| | 1,340 |
| | 1,340 |
| | — |
| | — |
| | — |
| | 40 |
| 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 80 |
| | 30 |
| | 165 |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 30 |
| 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 220 |
| | — |
| | — |
| | — |
| | 220 |
| | 195 |
| | 30 |
| | 15 |
| | 45 |
| | 175 |
| 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power (b) | — |
| | — |
| | — |
| | 600 |
| | 600 |
| | 566 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 70 |
| | — |
| | — |
| | — |
| | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Total | $ | 410 |
| | $ | 30 |
| | $ | 1,665 |
| | $ | 4,400 |
| | $ | 6,505 |
| | $ | 6,428 |
| | $ | 80 |
| | $ | 15 |
| | $ | 95 |
| | $ | 315 |
| |
Southern Company Consolidated | | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | ExcludesRepresents the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.Southern Company parent entity. |
| |
(b) | ExcludesDoes not include Southern Power's $120 million continuing letter of credit agreements (Project Credit Facilities) assumed with the acquisitionfacility for standby letters of certain solar facilities, which are non-recourse to Southern Power Company, the proceedscredit expiring in 2019, of which are being used to finance project costs related to such solar facilities currently under construction. See Note 12 to$19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the financial statements under "Southern Power"parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for additional information.which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements under "Bank"Bank Credit Arrangements"Arrangements" for additional information.
As reflected in the table above, in August 2015,In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restatedcertain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
dates from 2018 to 2020.Also in May 2017, Southern Company Gas Capital and Southern Power Company increasedNicor Gas terminated their borrowing ability under theseexisting credit arrangements to $1.25 billion from $1.0for $1.3 billion and $700 million, respectively, which were to $600 million from $500 million, respectively. Georgia Power increased its borrowing ability by $150 million under its facility maturingmature in 20202017 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015, Southern Company entered into an additional multi-year credit arrangement for $1 billion with a maturity date of 2018. Also in September 2015, Alabama Power2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million three-yearcurrently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, which replaced a majority ofthe allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power's bilateral credit arrangements. In November 2015, Gulf Power also amended and restated certain of its $500 million multi-year credit arrangementsarrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 20162017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross accelerationcross-acceleration or cross defaultcross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross defaultcross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, Southern Company, the traditional electric operating companies, and Southern Power Company, are currentlySouthern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs.programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 20152017 was approximately $1.8 billion.$1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2015,2017, the traditional electric operating companies had approximately $181$714 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.
At December 31, 2017, Pivotal Utility Holdings, Inc., a subsidiary of Southern Company intends to initially fundGas, had $200 million of gas facility revenue bonds outstanding. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the cash considerationtotal that are currently eligible for the Merger using a mix of debt and equity. Southern Company finances its capital needsredemption at par be redeemed on a portfolio basis and expects to issue approximately $8.0 billion in debtor prior to closing the Merger and approximately $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, Southern Power growth opportunities, and other Southern Company system capital projects. Southern Company expects to issue the debt to fund the Merger Consideration in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.
The Bridge Agreement provides for total loan commitments in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the Merger, the Bridge Agreementsale. See FUTURE EARNINGS POTENTIAL – "General" herein and the borrowings thereunder, the other financing transactions relatedNote 6 to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loanfinancial statements under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement (Closing Date).
In connection with the Bridge Agreement, Southern Company will pay a ticking fee"Gas Facility Revenue Bonds" for the benefit of the lenders thereto, accruing from November 21, 2015, in an amount equal to 0.125% per annum of the aggregate commitments under the Bridge Agreement, which fee will accrue through the earlier of (i) the date of termination of the commitments and (ii) the Closing Date. Additionally, under the terms of the Bridge Agreement, Southern Company is required to pay certain customary fees to the lenders as set forth in related letters. As of December 31, 2015, Southern Company had no outstanding loans under the Bridge Agreement.additional information.
Southern Company, the traditional electric operating companies and(other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks.above. Short-term borrowings are included in notes payable in the balance sheets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Details of short-term borrowings were as follows:
| | | Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) | Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017: | | | | | | | | | | |
Commercial paper | | $ | 1,832 |
| | 1.8 | % | | $ | 2,117 |
| | 1.3 | % | | $ | 2,946 |
|
Short-term bank debt | | 607 |
| | 2.3 | % | | 555 |
| | 2.1 | % | | 1,020 |
|
Total | | $ | 2,439 |
| | 1.9 | % | | $ | 2,672 |
| | 1.5 | % | | |
December 31, 2016: | | | | | | | | | | |
Commercial paper | | $ | 1,909 |
| | 1.1 | % | | $ | 976 |
| | 0.8 | % | | $ | 1,970 |
|
Short-term bank debt | | 123 |
| | 1.7 | % | | 176 |
| | 1.7 | % | | 500 |
|
Total | | $ | 2,032 |
| | 1.1 | % | | $ | 1,152 |
| | 1.1 | % | | |
December 31, 2015: | | | | | | | | | | | | | | | | | | |
Commercial paper | $ | 740 |
| | 0.7 | % | | $ | 842 |
| | 0.4 | % | | $ | 1,563 |
| $ | 740 |
| | 0.7 | % | | $ | 842 |
| | 0.4 | % | | $ | 1,563 |
|
Short-term bank debt | 500 |
| | 1.4 | % | | 444 |
| | 1.1 | % | | 795 |
| 500 |
| | 1.4 | % | | 444 |
| | 1.1 | % | | 795 |
|
Total | $ | 1,240 |
| | 0.9 | % | | $ | 1,286 |
| | 0.5 | % | | | $ | 1,240 |
| | 0.9 | % | | $ | 1,286 |
| | 0.5 | % | | |
December 31, 2014: | | | | | | | | | | |
Commercial paper | $ | 803 |
| | 0.3 | % | | $ | 754 |
| | 0.2 | % | | $ | 1,582 |
| |
Short-term bank debt | — |
| | — | % | | 98 |
| | 0.8 | % | | 400 |
| |
Total | $ | 803 |
| | 0.3 | % | | $ | 852 |
| | 0.3 | % | | | |
December 31, 2013: | | | | | | | | | | |
Commercial paper | $ | 1,082 |
| | 0.2 | % | | $ | 993 |
| | 0.3 | % | | $ | 1,616 |
| |
Short-term bank debt | 400 |
| | 0.9 | % | | 107 |
| | 0.9 | % | | 400 |
| |
Total | $ | 1,482 |
| | 0.4 | % | | $ | 1,100 |
| | 0.3 | % | | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month12-month periods ended December 31, 2015, 2014,2017, 2016, and 2013.2015. |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had total amountsa maximum amount outstanding as of December 31, 2015$828 million and an average amount outstanding of $137$566 million at a weighted average interest rate of 2.0%.2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.
Furthermore, in connection with the acquisition of a solar facility in July 2016, a subsidiary of Southern Power Company assumed a $217 million construction loan, which was fully repaid in September 2016. During this period, the credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.2%.
The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes,term loans, and operating cash flows.
Financing Activities
During 2015,2017, Southern Company issued approximately 6.614.6 million shares of common stock primarily through the employee equity compensation planplans and received proceeds of approximately $256$659 million. During
In addition, during the first nine monthssecond and third quarters of 2015, all sales under the Southern Investment Plan and the Employee Savings Plan were funded with shares acquired on the open market by independent plan administrators. In October 2015,2017, Southern Company began issuingissued a total of approximately 2.7 million shares of common stock through theat-the-market issuances pursuant to sales agency agreements related to Southern Investment PlanCompany's continuous equity offering program and the Employee Savings Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators.
On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares were repurchased in 2015 at a total costreceived cash proceeds of approximately $115 million. No further repurchases under the program are anticipated.$134 million, net of $1.1 million in fees and commissions.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2015:2017:
| | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds(a) | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(b) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| (in millions) | (in millions) |
Southern Company(b) | $ | 600 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 1,400 |
| | $ | — |
| $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 950 |
| | $ | 400 |
|
Alabama Power | 975 |
| | 650 |
| | 80 |
| | 134 |
| | — |
| | — |
| 1,100 |
| | 525 |
| | — |
| | 36 |
| | — |
| | — |
|
Georgia Power | 500 |
| | 1,175 |
| | 409 |
| | 267 |
| | 1,000 |
| | 6 |
| 1,350 |
| | 450 |
| | 65 |
| | 65 |
| | 370 |
| | 17 |
|
Gulf Power | — |
| | 60 |
| | 13 |
| | 13 |
| | — |
| | — |
| 300 |
| | 85 |
| | — |
| | — |
| | 6 |
| | — |
|
Mississippi Power | — |
| | — |
| | — |
| | — |
| | 275 |
| | 353 |
| — |
| | 35 |
| | — |
| | — |
| | 40 |
| | 962 |
|
Southern Power | 1,650 |
| | 525 |
| | — |
| | — |
| | 402 |
| | 4 |
| 525 |
| | 500 |
| | — |
| | — |
| | 43 |
| | 18 |
|
Southern Company Gas(c) | | 450 |
| | — |
| | — |
| | — |
| | 400 |
| | 22 |
|
Other | — |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
Elimination(c) | — |
| | — |
| | — |
| | — |
| | (275 | ) | | — |
| |
Total | $ | 3,725 |
| | $ | 2,810 |
| | $ | 502 |
| | $ | 414 |
| | $ | 2,802 |
| | $ | 380 |
| |
Elimination(d) | | — |
| | — |
| | — |
| | — |
| | (40 | ) | | (602 | ) |
Southern Company Consolidated | | $ | 4,025 |
| | $ | 1,995 |
| | $ | 65 |
| | $ | 101 |
| | $ | 1,769 |
| | $ | 832 |
|
| |
(a) | Includes a reoffering by Alabama Power of $80.0 million aggregate principal amount of revenue bonds purchased and held since April 2015; reofferings by Georgia Power of $135.2 million, $104.6 million, and $65.0 million aggregate principal amount of revenue bonds purchased and held since 2010, 2013, and April 2015, respectively; and a reoffering by Gulf Power of $13.0 million aggregate principal amount of revenue bonds purchased and held in July 2015. Also includes repurchases and reofferings by Georgia Power of $94.6 million and $10.0 million aggregate principal amount of revenue bonds in August 2015 in connection with optional tenders. |
| |
(b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | Intercompany loanThe senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas. |
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
In September 2015, Southern Company entered into a $400 million aggregate principal amount 18-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
Also in September 2015, Southern Company repaid at maturity $400 million aggregate principal amount of its Series 2010A 2.375% Senior Notes due September 15, 2015.
In October 2015, Southern Company issued $1.0 billion aggregate principal amount of Series 2015A 6.25% Junior Subordinated Notes due October 15, 2075. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
In November and December 2015, Southern Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $2 billion. Subsequent to December 31, 2015, Southern Company entered into an additional $700 million notional amount of forward-starting interest rate swaps.
Except as otherwise described herein, Southern Company'sCompany and its subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programsprograms.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and for$300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.
In September 2017, Alabama Power its growth strategy.
issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A portionPreferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The majority of the proceeds of Alabama Power's senior note issuances were used in May 2015October 2017 to redeem 6.48all 2 million shares ($16250 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred6.50% Series Preference Stock, at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.06 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625%6.45% Series Preference Stock, at a redemption priceand 1.52 million shares ($38 million aggregate stated capital) of $25 per share plus accrued and unpaid dividends to the redemption date.Alabama Power's 5.83% Class A Preferred Stock.
In June 2017, Georgia Power's "Other Long-Term Debt Issuances" reflectedPower entered into two short-term floating rate bank loans in the table above include borrowings in June and December 2015 under the FFB Credit Facility in an aggregate principal amountamounts of $600$50 million and $400$150 million, respectively. The interestwith maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
applicable to the $600loan of $100 million, principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072%, both for an interest period that extends to the finalwith a maturity date of February 20, 2044.June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to reimburseredeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power for Eligible Project Costs relating to the constructionPower's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Plant Vogtle Units 3 and 4.Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2015, Georgia2017, Gulf Power entered into a $250extended the maturity of its $100 million aggregate principal amount three-monthshort-term floating rate bank loan bearing interest based on one-month LIBOR. TheLIBOR from April 2017 to October 2017 and subsequently repaid the loan was repaid at maturity.in May 2017.
In April 2015, Mississippi Power entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. A portion of the proceeds of these loans wereGulf Power's senior note issuances was used forin June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the repayment of term loans in an aggregateoutstanding principal amount of $275 million. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In addition to the amounts reflected in the table above, Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant tounder its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of approximately $301 million bearing interest based on one-month LIBOR,$1.2 billion unsecured term loan, which matures on December 1, 2017. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for additional information.March 30, 2018.
In June 2015, GulfSeptember 2017, Southern Power entered into a $40amended its $60 million aggregate principal amount three-month floating rate bankterm loan bearing interest based on one-month LIBOR. The loan was repaid at maturity.
In October 2015, Gulf Power entered into forward-starting interest rate swaps to, hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount ofamong other things, increase the swaps totaled $80 million.
Subsequent to December 31, 2015, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at$100 million and extend the maturity $200 million aggregate principal amount of its Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.
Subsequentdate from September 2017 to December 31, 2015, Southern Power borrowed $182 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.0%.October 2018.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
At December 31, 2017, Southern Company and its subsidiaries dodid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at December 31, 20152017 were as follows:
| | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| (in millions) | (in millions) |
At BBB and/or Baa2 | $ | 12 |
| $ | 40 |
|
At BBB- and/or Baa3 | $ | 508 |
| $ | 665 |
|
Below BBB- and/or Baa3 | $ | 2,432 |
| |
At BB+ and/or Ba1(*) | | $ | 2,390 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets and would be likely to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
impact the cost at which they do so.
On June 5, 2015, Fitch Ratings, Inc. (Fitch) downgraded the long-term issuer default rating of Mississippi Power to BBB+ from A-. Fitch maintained the negative ratings outlook for Mississippi Power and revised the ratings outlook for Southern Company from stable to negative.
On August 14, 2015,March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Baa2Ba1 from Baa1.Baa3.
On March 20, 2017, Moody's maintained the negative ratingsrevised its rating outlook for Mississippi Power.Georgia Power from stable to negative.
On August 17, 2015, S&P downgraded the consolidated long-term issuer rating of Southern Company (including Alabama Power, Georgia Power, and Gulf Power) to A- from A. Also on August 17, 2015, S&P downgraded the issuer rating of Mississippi Power to BBB+ from A.March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, to stable from negative. Separately, on August 24, 2015, S&P revised its credit rating outlook forSouthern Power, Southern Company the traditional operating companies,Gas, Southern Company Gas Capital, and Southern Power CompanyNicor Gas) from stable to negative following the announcement of the Merger.negative.
Also following the announcement of the Merger, on August 24, 2015, Moody's affirmed the rating of Southern Company and revised its credit rating outlook from stable to negative. On the same date,March 30, 2017, Fitch Ratings, Inc. placed the ratings of Southern Company, Georgia Power, and Mississippi Power on ratingsrating watch negative.
On November 5, 2015,June 22, 2017, Moody's downgradedplaced the senior unsecured debt ratingratings of Mississippi Power to Baa3 from Baa2.on review for downgrade. On September 21, 2017, Moody's maintained the negative ratingsrevised its rating outlook for Mississippi Power.Power from under review to stable.
On January 19, 2018, Moody's revised its rating outlooks for Southern Company and Alabama Power from stable to negative.
While it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Absent actions by Southern Company and its subsidiaries to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation.
Market Price Risk
The Southern Company system is exposed to market risks, primarilyincluding commodity price risk, and interest rate risk. The Southern Company system may alsorisk, weather risk, and occasionally have limited exposure to foreign currency exchange rates.rate risk. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. The Southern Company system'sGas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 20152017 have a notional amount of $4.2$3.7 billion of which $2.3 billionand are intended to mitigate interest rate volatility related to projected debt financings in 2016. The remaining $1.9 billion are related to existing fixed and floating rate obligations. The weighted average interest rate on $5.2$6.3 billion of long-term variable interest rate exposure at January 1, 2016December 31, 2017 was 1.19%2.43%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $52$63 million at January 1, 2016.December 31, 2017. See Note 1 to the financial statements under "Financial Instruments""Financial Instruments" and Note 11 to the financial statements for additional information.
Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. The traditional electric operating companies continue toand certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs.PSCs or other applicable state regulatory agencies. Southern Company had no material change in market risk exposure for the year ended December 31, 20152017 when compared to the year ended December 31, 2014.2016.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2015 Changes | | 2014 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (188 | ) | | $ | (32 | ) |
Contracts realized or settled: | | | |
Swaps realized or settled | 121 |
| | (9 | ) |
Options realized or settled | 21 |
| | 6 |
|
Current period changes(*): | | | |
Swaps | (152 | ) | | (131 | ) |
Options | (15 | ) | | (22 | ) |
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (213 | ) | | $ | (188 | ) |
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | 41 |
| | $ | (213 | ) |
Acquisitions | — |
| | (54 | ) |
Contracts realized or settled | (8 | ) | | 141 |
|
Current period changes(a) | (196 | ) | | 171 |
|
Contracts outstanding at the end of the period, assets (liabilities), net(b) | $ | (163 | ) | | $ | 45 |
|
| |
(*)(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
| |
(b) | Excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016. |
The net hedge volumes of energy-related derivative contracts were 621 million mmBtu and 500 million mmBtu for the years ended December 31, were as follows:2017 and 2016, respectively.
|
| | | | | |
| 2015 | | 2014 |
| mmBtu Volume |
| (in millions) |
Commodity – Natural gas swaps | 168 |
| | 200 |
|
Commodity – Natural gas options | 56 |
| | 44 |
|
Total hedge volume | 224 |
| | 244 |
|
TheFor the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or (below) market prices was approximately $1.14$0.15 per mmBtu as of December 31, 20152017 and $0.84$(0.05) per mmBtu as of December 31, 2014. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price.2016. The majority of the natural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.
At December 31, 20152017 and 2014,2016, substantially all of the Southern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the fair value hierarchy, and Subsidiary Companies 2015 Annual Report
Southern Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2.2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts which are all Level 2 of the fair value hierarchy, at December 31, 20152017 were as follows:
| | | Fair Value Measurements | Fair Value Measurements |
| December 31, 2015 | December 31, 2017 |
| Total Fair Value | | Maturity | Total Fair Value | | Maturity |
| | Year 1 | | Years 2&3 | | Years 4&5 | | Year 1 | | Years 2&3 | | Years 4&5 |
| (in millions) | (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | (148 | ) | | $ | (71 | ) | | $ | (59 | ) | | $ | (18 | ) |
Level 2 | 213 |
| | 126 |
| | 82 |
| | 5 |
| (15 | ) | | (30 | ) | | 13 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | 213 |
| | $ | 126 |
| | $ | 82 |
| | $ | 5 |
| $ | (163 | ) | | $ | (101 | ) | | $ | (46 | ) | | $ | (16 | ) |
The Southern Company system is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Southern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments""Financial Instruments" and Note 11 to the financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
With the exception of Southern Company Gas' subsidiary, Atlanta Gas Light, and the Southern Company Gas wholesale gas services business, the Southern Company system is not exposed to concentrations of credit risk. Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 natural gas marketers in Georgia responsible for the retail sale of natural gas to end-use customers in Georgia. For 2017, the four largest natural gas marketers based on customer count accounted for 19% of Southern Company Gas' adjusted operating margin. Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2017, Southern Company Gas' wholesale gas services business' top 20 counterparties represented approximately 48%, or $203 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year.
Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.
Capital Requirements and Contractual Obligations
The Southern Company system's construction program is currently estimated to total $7.3approximately $9.4 billion for 2016, $5.22018, $9.3 billion for 2017, and $5.52019, $8.4 billion for 2018.2020, $7.0 billion for 2021, and $6.9 billion for 2022. These amounts include expenditures of approximately $0.6$1.2 billion, related to the construction and start-up of the Kemper IGCC in 2016; $0.6$1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion to continuefor the construction onof Plant Vogtle Units 3 and 4 in 2016, 2017,2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $1.3 billion per year for 2018 respectively;through 2022 for Southern Power's planned expenditures for plant acquisitions and $2.2 billion, $0.9 billion, and $1.4 billion for acquisitions and/or construction of new Southern Power generating facilities in 2016, 2017, and 2018, respectively.placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.LTSAs. Estimated capital expenditures to comply with environmental statuteslaws and regulations included in these amounts are $0.7$1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.6$0.5 billion for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA's final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-firedfossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental"Environmental Matters – Environmental StatutesLaws and Regulations"Regulations" and "– " – Global Climate Issues"Issues" herein for additional information.
The Southern Company systemtraditional electric operating companies also anticipatesanticipate costs associated with closure in place or by other methods, and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with the Company's ARO liabilities. These costs, which could change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be approximately $0.2$0.3 billion, $0.2$0.3 billion, $0.4 billion, $0.5 billion, and $0.3$0.4 billion for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. See Note 1 to the financial statements under "Asset"Asset Retirement Obligations and Other Costs of Removal"Removal" for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; PSCstate regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements under "Southern Power""Southern Power" for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" for information regarding additional factors that may impact construction expenditures.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been finalized or previously constructed, including first-of-a-kind technology, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development, construction, and constructionoperation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC).
In addition to the Merger Consideration to be paid by Southern Company at the Effective Time, in connection with the Merger, Southern Company will also assume AGL Resources' outstanding indebtedness (approximately $4.8 billion at December 31, 2015).performance. See OVERVIEW herein for additional information regarding the Merger, including the Merger Consideration, as well as Note 123 to the financial statements.statements under "Nuclear Construction" for information regarding additional factors that may impact construction expenditures.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Southern Company system provides postretirement benefits to substantially allthe majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the traditional operating companies' respective regulatory commissions.FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, unrecognized tax benefits, pipeline charges, storage capacity, gas supply, asset management agreements, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Contractual Obligations
The Southern Company system's contractual obligations at December 31, 2017 were as follows:
| | | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total | 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) | (in millions) |
Long-term debt(a) — | | | | | | | | | | | | | | | | | | |
Principal | $ | 2,642 |
| | $ | 4,128 |
| | $ | 2,572 |
| | $ | 18,090 |
| | $ | 27,432 |
| $ | 3,865 |
| | $ | 6,293 |
| | $ | 5,206 |
| | $ | 32,610 |
| | $ | 47,974 |
|
Interest | 997 |
| | 1,794 |
| | 1,576 |
| | 14,948 |
| | 19,315 |
| 1,782 |
| | 3,286 |
| | 2,793 |
| | 27,535 |
| | 35,396 |
|
Preferred and preference stock dividends(b) | 45 |
| | 91 |
| | 91 |
| | — |
| | 227 |
| |
Preferred stock dividends of subsidiaries(b) | | 16 |
| | 33 |
| | 33 |
| | — |
| | 82 |
|
Financial derivative obligations(c) | 156 |
| | 83 |
| | 5 |
| | — |
| | 244 |
| 493 |
| | 198 |
| | 37 |
| | 5 |
| | 733 |
|
Operating leases(d) | 121 |
| | 184 |
| | 114 |
| | 706 |
| | 1,125 |
| 149 |
| | 232 |
| | 178 |
| | 968 |
| | 1,527 |
|
Capital leases(d) | 32 |
| | 28 |
| | 23 |
| | 63 |
| | 146 |
| 39 |
| | 43 |
| | 20 |
| | 232 |
| | 334 |
|
Unrecognized tax benefits(e) | 9 |
| | 424 |
| | — |
| | — |
| | 433 |
| 18 |
| | — |
| | — |
| | — |
| | 18 |
|
Pipeline charges, storage capacity, and gas supply(f) | | 813 |
| | 968 |
| | 714 |
| | 2,294 |
| | 4,789 |
|
Asset management agreements(g) | | 9 |
| | 6 |
| | — |
| | — |
| | 15 |
|
Purchase commitments — | | | | | | | | |
|
| | | | | | | | |
|
|
Capital(f) | 6,906 |
| | 9,780 |
| | — |
| | — |
| | 16,686 |
| |
Fuel(g) | 3,201 |
| | 4,473 |
| | 2,566 |
| | 7,378 |
| | 17,618 |
| |
Purchased power(h) | 380 |
| | 803 |
| | 840 |
| | 3,762 |
| | 5,785 |
| |
Other(i) | 281 |
| | 637 |
| | 482 |
| | 1,661 |
| | 3,061 |
| |
Capital(h) | | 9,016 |
| | 16,905 |
| | 12,749 |
| | — |
| | 38,670 |
|
Fuel(i) | | 3,156 |
| | 3,573 |
| | 1,927 |
| | 5,588 |
| | 14,244 |
|
Purchased power(j) | | 424 |
| | 884 |
| | 886 |
| | 3,716 |
| | 5,910 |
|
Other(k) | | 407 |
| | 713 |
| | 434 |
| | 2,745 |
| | 4,299 |
|
Trusts — | | | | | | | | |
|
| | | | | | | | |
|
|
Nuclear decommissioning(j) | 5 |
| | 11 |
| | 11 |
| | 104 |
| | 131 |
| |
Pension and other postretirement benefit plans(k) | 117 |
| | 232 |
| | — |
| | — |
| | 349 |
| |
Nuclear decommissioning(l) | | 5 |
| | 11 |
| | 11 |
| | 94 |
| | 121 |
|
Pension and other postretirement benefit plans(m) | | 137 |
| | 275 |
| | — |
| | — |
| | 412 |
|
Total | $ | 14,892 |
| | $ | 22,668 |
| | $ | 8,280 |
| | $ | 46,712 |
| | $ | 92,552 |
| $ | 20,329 |
| | $ | 33,420 |
| | $ | 24,988 |
| | $ | 75,787 |
| | $ | 154,524 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings.borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE"DOE Loan Guarantee Borrowings"Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2016,December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Represents preferred and preference stock of subsidiaries. Preferred and preference stock dodoes not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, seeSee Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and included in "Purchased power." |
| |
(e) | See Note 5 to the financial statements under "Unrecognized"Unrecognized Tax Benefits"Benefits" for additional information. |
| |
(f) | Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. |
| |
(g) | Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services. |
| |
(h) | The Southern Company system provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreementsLTSAs which are reflected in "Fuel" and "Other," respectively. At December 31, 2015,2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental"Environmental Matters – Environmental StatutesLaws and Regulations"Regulations" herein for additional information. |
| |
(g)(i) | Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(h)(j) | Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $304 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Georgia Power – Renewables Development" herein for additional information. |
| |
(i)(k) | Includes long-term service agreements,LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. Long-term service agreementsLTSAs include price escalation based on inflation indices. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
| |
(j)(l) | Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information. |
| |
(k)(m) | The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension planplans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retailregulated rates, the potential financing of the Merger, the expected timing of the completion of the Merger, the strategic goals for the wholesale business, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan,plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources,completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and constructionoperation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company'sCompany system's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;
actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
litigation related to the Kemper County energy facility;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas and the potential sale of a 33% equity interest in substantially all of Southern Power's solar assets, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and AGL ResourcesSouthern Company Gas will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;expected;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's subsidiarieselectric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by Southern Company from time to time with the SEC.
Southern Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Retail revenues | $ | 14,987 |
| | $ | 15,550 |
| | $ | 14,541 |
| |
Wholesale revenues | 1,798 |
| | 2,184 |
| | 1,855 |
| |
Retail electric revenues | | $ | 15,330 |
| | $ | 15,234 |
| | $ | 14,987 |
|
Wholesale electric revenues | | 2,426 |
| | 1,926 |
| | 1,798 |
|
Other electric revenues | 657 |
| | 672 |
| | 639 |
| 681 |
| | 698 |
| | 657 |
|
Natural gas revenues | | 3,791 |
| | 1,596 |
| | — |
|
Other revenues | 47 |
| | 61 |
| | 52 |
| 803 |
| | 442 |
| | 47 |
|
Total operating revenues | 17,489 |
| | 18,467 |
| | 17,087 |
| 23,031 |
| | 19,896 |
| | 17,489 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 4,750 |
| | 6,005 |
| | 5,510 |
| 4,400 |
| | 4,361 |
| | 4,750 |
|
Purchased power | 645 |
| | 672 |
| | 461 |
| 863 |
| | 750 |
| | 645 |
|
Cost of natural gas | | 1,601 |
| | 613 |
| | — |
|
Cost of other sales | | 513 |
| | 260 |
| | — |
|
Other operations and maintenance | 4,416 |
| | 4,354 |
| | 3,846 |
| 5,481 |
| | 5,240 |
| | 4,416 |
|
Depreciation and amortization | 2,034 |
| | 1,945 |
| | 1,901 |
| 3,010 |
| | 2,502 |
| | 2,034 |
|
Taxes other than income taxes | 997 |
| | 981 |
| | 934 |
| 1,250 |
| | 1,113 |
| | 997 |
|
Estimated loss on Kemper IGCC | 365 |
| | 868 |
| | 1,180 |
| 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 13,207 |
| | 14,825 |
| | 13,832 |
| 20,480 |
| | 15,267 |
| | 13,207 |
|
Operating Income | 4,282 |
| | 3,642 |
| | 3,255 |
| 2,551 |
| | 4,629 |
| | 4,282 |
|
Other Income and (Expense): | | | | | | | | | | |
Allowance for equity funds used during construction | 226 |
| | 245 |
| | 190 |
| 160 |
| | 202 |
| | 226 |
|
Interest income | 23 |
| | 19 |
| | 19 |
| |
Earnings from equity method investments | | 106 |
| | 59 |
| | — |
|
Interest expense, net of amounts capitalized | (840 | ) | | (835 | ) | | (824 | ) | (1,694 | ) | | (1,317 | ) | | (840 | ) |
Other income (expense), net | (62 | ) | | (63 | ) | | (81 | ) | (55 | ) | | (93 | ) | | (39 | ) |
Total other income and (expense) | (653 | ) | | (634 | ) | | (696 | ) | (1,483 | ) | | (1,149 | ) | | (653 | ) |
Earnings Before Income Taxes | 3,629 |
| | 3,008 |
| | 2,559 |
| 1,068 |
| | 3,480 |
| | 3,629 |
|
Income taxes | 1,194 |
| | 977 |
| | 849 |
| 142 |
| | 951 |
| | 1,194 |
|
Consolidated Net Income | 2,435 |
| | 2,031 |
| | 1,710 |
| 926 |
| | 2,529 |
| | 2,435 |
|
Less: | | | | | | | | | | |
Dividends on preferred and preference stock of subsidiaries | 54 |
| | 68 |
| | 66 |
| 38 |
| | 45 |
| | 54 |
|
Net income attributable to noncontrolling interests | 14 |
| | — |
| | — |
| 46 |
| | 36 |
| | 14 |
|
Consolidated Net Income Attributable to Southern Company | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
| $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Common Stock Data: | | | | | | | | | | |
Earnings per share (EPS) — | | | | | | |
Basic EPS | $ | 2.60 |
| | $ | 2.19 |
| | $ | 1.88 |
| |
Diluted EPS | 2.59 |
| | 2.18 |
| | 1.87 |
| |
Earnings per share — | | | | | | |
Basic | | $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
|
Diluted | | 0.84 |
| | 2.55 |
| | 2.59 |
|
Average number of shares of common stock outstanding — (in millions) | | | | | | | | | | |
Basic | 910 |
| | 897 |
| | 877 |
| 1,000 |
| | 951 |
| | 910 |
|
Diluted | 914 |
| | 901 |
| | 881 |
| 1,008 |
| | 958 |
| | 914 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Consolidated Net Income | $ | 2,435 |
| | $ | 2,031 |
| | $ | 1,710 |
| $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Other comprehensive income: | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $(8), $(6), and $-, respectively | (13 | ) | | (10 | ) | | — |
| |
Reclassification adjustment for amounts included in net income, net of tax of $4, $3, and $5, respectively | 6 |
| | 5 |
| | 9 |
| |
Marketable securities: | | | | | | |
Change in fair value, net of tax of $-, $-, and $(2), respectively | — |
| | — |
| | (3 | ) | |
Changes in fair value, net of tax of $34, $(84), and $(8), respectively | | 57 |
| | (136 | ) | | (13 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(37), $43, and $4, respectively | | (60 | ) | | 69 |
| | 6 |
|
Pension and other postretirement benefit plans: | | | | | | | | | | |
Benefit plan net gain (loss), net of tax of $(1), $(32), and $22, respectively | (2 | ) | | (51 | ) | | 36 |
| |
Reclassification adjustment for amounts included in net income, net of tax of $4, $2, and $4, respectively | 7 |
| | 3 |
| | 6 |
| |
Benefit plan net gain (loss), net of tax of $6, $10, and $(1), respectively | | 17 |
| | 13 |
| | (2 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(6), $3, and $4, respectively | | (23 | ) | | 4 |
| | 7 |
|
Total other comprehensive income (loss) | (2 | ) | | (53 | ) | | 48 |
| (9 | ) | | (50 | ) | | (2 | ) |
Less: | | | | | | | | | | |
Dividends on preferred and preference stock of subsidiaries | 54 |
| | 68 |
| | 66 |
| 38 |
| | 45 |
| | 54 |
|
Comprehensive income attributable to noncontrolling interests | 14 |
| | — |
| | — |
| 46 |
| | 36 |
| | 14 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 2,365 |
| | $ | 1,910 |
| | $ | 1,692 |
| $ | 833 |
| | $ | 2,398 |
| | $ | 2,365 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| | | (in millions) | | | (in millions) |
Operating Activities: | | | | | | | | | | |
Consolidated net income | $ | 2,435 |
| | $ | 2,031 |
| | $ | 1,710 |
| $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization, total | 2,395 |
| | 2,293 |
| | 2,298 |
| 3,457 |
| | 2,923 |
| | 2,395 |
|
Deferred income taxes | 1,404 |
| | 709 |
| | 496 |
| 166 |
| | (127 | ) | | 1,404 |
|
Investment tax credits | (48 | ) | | 35 |
| | 302 |
| |
Collateral deposits | | (4 | ) | | (102 | ) | | — |
|
Allowance for equity funds used during construction | (226 | ) | | (245 | ) | | (190 | ) | (160 | ) | | (202 | ) | | (226 | ) |
Pension, postretirement, and other employee benefits | 76 |
| | (515 | ) | | 131 |
| |
Pension and postretirement funding | | (2 | ) | | (1,029 | ) | | (7 | ) |
Settlement of asset retirement obligations | | (177 | ) | | (171 | ) | | (37 | ) |
Stock based compensation expense | 99 |
| | 63 |
| | 59 |
| 109 |
| | 121 |
| | 99 |
|
Hedge settlements | | 6 |
| | (233 | ) | | (17 | ) |
Estimated loss on Kemper IGCC | 365 |
| | 868 |
| | 1,180 |
| 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | (413 | ) | | — |
| | — |
| (47 | ) | | (122 | ) | | (413 | ) |
Other, net | (39 | ) | | (39 | ) | | (41 | ) | (109 | ) | | (99 | ) | | 49 |
|
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | 243 |
| | (352 | ) | | (153 | ) | (199 | ) | | (544 | ) | | 243 |
|
-Fossil fuel stock | 61 |
| | 408 |
| | 481 |
| |
-Materials and supplies | (44 | ) | | (67 | ) | | 36 |
| |
-Fossil fuel for generation | | 36 |
| | 178 |
| | 61 |
|
-Natural gas for sale | | 36 |
| | (226 | ) | | — |
|
-Other current assets | (108 | ) | | (57 | ) | | (11 | ) | (143 | ) | | (206 | ) | | (152 | ) |
-Accounts payable | (353 | ) | | 267 |
| | 72 |
| (280 | ) | | 301 |
| | (353 | ) |
-Accrued taxes | 352 |
| | (105 | ) | | (85 | ) | (142 | ) | | 1,456 |
| | 352 |
|
-Accrued compensation | (41 | ) | | 255 |
| | (138 | ) | |
-Retail fuel cost over recovery — short-term | 289 |
| | (23 | ) | | (66 | ) | |
-Retail fuel cost over recovery | | (212 | ) | | (231 | ) | | 289 |
|
-Mirror CWIP | (271 | ) | | 180 |
| | — |
| — |
| | — |
| | (271 | ) |
-Other current liabilities | 98 |
| | 109 |
| | 16 |
| (45 | ) | | 250 |
| | 58 |
|
Net cash provided from operating activities | 6,274 |
| | 5,815 |
| | 6,097 |
| 6,395 |
| | 4,894 |
| | 6,274 |
|
Investing Activities: | | | | | | | | | | |
Plant acquisitions | (1,719 | ) | | (731 | ) | | (132 | ) | |
Business acquisitions, net of cash acquired | | (1,070 | ) | | (10,689 | ) | | (1,719 | ) |
Property additions | (5,674 | ) | | (5,246 | ) | | (5,331 | ) | (7,423 | ) | | (7,310 | ) | | (5,674 | ) |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | | 1,682 |
| | — |
| | — |
|
Investment in restricted cash | (160 | ) | | (11 | ) | | (149 | ) | (17 | ) | | (733 | ) | | (160 | ) |
Distribution of restricted cash | 154 |
| | 57 |
| | 96 |
| 34 |
| | 742 |
| | 154 |
|
Nuclear decommissioning trust fund purchases | (1,424 | ) | | (916 | ) | | (986 | ) | (811 | ) | | (1,160 | ) | | (1,424 | ) |
Nuclear decommissioning trust fund sales | 1,418 |
| | 914 |
| | 984 |
| 805 |
| | 1,154 |
| | 1,418 |
|
Cost of removal, net of salvage | (167 | ) | | (170 | ) | | (131 | ) | (313 | ) | | (245 | ) | | (167 | ) |
Change in construction payables, net | 402 |
| | (107 | ) | | (126 | ) | 259 |
| | (121 | ) | | 402 |
|
Prepaid long-term service agreement | (197 | ) | | (181 | ) | | (91 | ) | |
Investment in unconsolidated subsidiaries | | (152 | ) | | (1,444 | ) | | — |
|
Payments pursuant to LTSAs | | (227 | ) | | (134 | ) | | (197 | ) |
Other investing activities | 87 |
| | (17 | ) | | 124 |
| 42 |
| | (108 | ) | | 87 |
|
Net cash used for investing activities | (7,280 | ) | | (6,408 | ) | | (5,742 | ) | (7,191 | ) | | (20,048 | ) | | (7,280 | ) |
Financing Activities: | | | | | | | | | | |
Increase (decrease) in notes payable, net | 73 |
| | (676 | ) | | 662 |
| (401 | ) | | 1,228 |
| | 73 |
|
Proceeds — | | | | | | | | | | |
Long-term debt issuances | 7,029 |
| | 3,169 |
| | 2,938 |
| |
Interest-bearing refundable deposit | — |
| | 125 |
| | — |
| |
Common stock issuances | 256 |
| | 806 |
| | 695 |
| |
Long-term debt | | 5,858 |
| | 16,368 |
| | 7,029 |
|
Common stock | | 793 |
| | 3,758 |
| | 256 |
|
Preferred stock | | 250 |
| | — |
| | — |
|
Short-term borrowings | 755 |
| | — |
| | — |
| 1,259 |
| | — |
| | 755 |
|
Redemptions and repurchases — | | | | | | | | | | |
Long-term debt | (3,604 | ) | | (816 | ) | | (2,830 | ) | (2,930 | ) | | (3,145 | ) | | (3,604 | ) |
Common stock repurchased | (115 | ) | | (5 | ) | | (20 | ) | |
Common stock | | — |
| | — |
| | (115 | ) |
Interest-bearing refundable deposits | (275 | ) | | — |
| | — |
| — |
| | — |
| | (275 | ) |
Preferred and preference stock | (412 | ) | | — |
| | — |
| (658 | ) | | — |
| | (412 | ) |
Short-term borrowings | (255 | ) | | — |
| | — |
| (659 | ) | | (478 | ) | | (255 | ) |
Distributions to noncontrolling interests | | (119 | ) | | (72 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 341 |
| | 8 |
| | 17 |
| 80 |
| | 682 |
| | 341 |
|
Payment of common stock dividends | (1,959 | ) | | (1,866 | ) | | (1,762 | ) | (2,300 | ) | | (2,104 | ) | | (1,959 | ) |
Payment of dividends on preferred and preference stock of subsidiaries | (59 | ) | | (68 | ) | | (66 | ) | |
Other financing activities | (75 | ) | | (33 | ) | | 42 |
| (222 | ) | | (512 | ) | | (116 | ) |
Net cash provided from (used for) financing activities | 1,700 |
| | 644 |
| | (324 | ) | |
Net cash provided from financing activities | | 951 |
| | 15,725 |
| | 1,700 |
|
Net Change in Cash and Cash Equivalents | 694 |
| | 51 |
| | 31 |
| 155 |
| | 571 |
| | 694 |
|
Cash and Cash Equivalents at Beginning of Year | 710 |
| | 659 |
| | 628 |
| 1,975 |
| | 1,404 |
| | 710 |
|
Cash and Cash Equivalents at End of Year | $ | 1,404 |
| | $ | 710 |
| | $ | 659 |
| $ | 2,130 |
| | $ | 1,975 |
| | $ | 1,404 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 20152017 and 20142016
Southern Company and Subsidiary Companies 20152017 Annual Report
| | Assets | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 1,404 |
| | $ | 710 |
| $ | 2,130 |
| | $ | 1,975 |
|
Receivables — | | | | | | |
Customer accounts receivable | 1,058 |
| | 1,090 |
| 1,806 |
| | 1,583 |
|
Energy marketing receivable | | 607 |
| | 623 |
|
Unbilled revenues | 397 |
| | 432 |
| 810 |
| | 706 |
|
Under recovered regulatory clause revenues | 63 |
| | 136 |
| |
Under recovered fuel clause revenues | | 171 |
| | — |
|
Income taxes receivable, current | | 63 |
| | 544 |
|
Other accounts and notes receivable | 398 |
| | 307 |
| 635 |
| | 377 |
|
Accumulated provision for uncollectible accounts | (13 | ) | | (18 | ) | (44 | ) | | (43 | ) |
Income taxes receivable, current | 144 |
| | — |
| |
Fossil fuel stock, at average cost | 868 |
| | 930 |
| |
Materials and supplies, at average cost | 1,061 |
| | 1,039 |
| |
Vacation pay | 178 |
| | 177 |
| |
Materials and supplies | | 1,438 |
| | 1,462 |
|
Fossil fuel for generation | | 594 |
| | 689 |
|
Natural gas for sale | | 595 |
| | 631 |
|
Prepaid expenses | 495 |
| | 665 |
| 452 |
| | 364 |
|
Other regulatory assets, current | 402 |
| | 346 |
| 604 |
| | 581 |
|
Other current assets | 71 |
| | 50 |
| 211 |
| | 230 |
|
Total current assets | 6,526 |
| | 5,864 |
| 10,072 |
| | 9,722 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 75,118 |
| | 70,013 |
| 103,542 |
| | 98,416 |
|
Less accumulated depreciation | 24,253 |
| | 24,059 |
| |
Less: Accumulated depreciation | | 31,457 |
| | 29,852 |
|
Plant in service, net of depreciation | 50,865 |
| | 45,954 |
| 72,085 |
| | 68,564 |
|
Other utility plant, net | 233 |
| | 211 |
| |
Nuclear fuel, at amortized cost | 934 |
| | 911 |
| 883 |
| | 905 |
|
Construction work in progress | 9,082 |
| | 7,792 |
| 6,904 |
| | 8,977 |
|
Total property, plant, and equipment | 61,114 |
| | 54,868 |
| 79,872 |
| | 78,446 |
|
Other Property and Investments: | | | | | | |
Goodwill | | 6,268 |
|
| 6,251 |
|
Equity investments in unconsolidated subsidiaries | | 1,513 |
|
| 1,549 |
|
Other intangible assets, net of amortization of $186 and $62 at December 31, 2017 and December 31, 2016, respectively | | 873 |
| | 970 |
|
Nuclear decommissioning trusts, at fair value | 1,512 |
| | 1,546 |
| 1,832 |
| | 1,606 |
|
Leveraged leases | 755 |
| | 743 |
| 775 |
| | 774 |
|
Miscellaneous property and investments | 485 |
| | 203 |
| 249 |
| | 270 |
|
Total other property and investments | 2,752 |
| | 2,492 |
| 11,510 |
| | 11,420 |
|
Deferred Charges and Other Assets: | | | | | | |
Deferred charges related to income taxes | 1,560 |
| | 1,510 |
| 825 |
| | 1,629 |
|
Unamortized loss on reacquired debt | 227 |
| | 243 |
| 206 |
| | 223 |
|
Other regulatory assets, deferred | 4,989 |
| | 4,334 |
| 6,943 |
| | 6,851 |
|
Income taxes receivable, non-current | 413 |
| | — |
| |
Other deferred charges and assets | 737 |
| | 922 |
| 1,577 |
| | 1,406 |
|
Total deferred charges and other assets | 7,926 |
| | 7,009 |
| 9,551 |
| | 10,109 |
|
Total Assets | $ | 78,318 |
| | $ | 70,233 |
| $ | 111,005 |
| | $ | 109,697 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 20152017 and 20142016
Southern Company and Subsidiary Companies 20152017 Annual Report
| | Liabilities and Stockholders' Equity | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Liabilities: | | | | | | |
Securities due within one year | $ | 2,674 |
| | $ | 3,329 |
| $ | 3,892 |
| | $ | 2,587 |
|
Interest-bearing refundable deposits | — |
| | 275 |
| |
Notes payable | 1,376 |
| | 803 |
| 2,439 |
| | 2,241 |
|
Energy marketing trade payables | | 546 |
| | 597 |
|
Accounts payable | 1,905 |
| | 1,593 |
| 2,530 |
| | 2,228 |
|
Customer deposits | 404 |
| | 390 |
| 542 |
| | 558 |
|
Accrued taxes — | | | | | | |
Accrued income taxes | 19 |
| | 149 |
| 6 |
| | 193 |
|
Unrecognized tax benefits | | 18 |
| | 385 |
|
Other accrued taxes | 484 |
| | 487 |
| 613 |
| | 667 |
|
Accrued interest | 249 |
| | 295 |
| 488 |
| | 518 |
|
Accrued vacation pay | 228 |
| | 223 |
| |
Accrued compensation | 549 |
| | 576 |
| 959 |
| | 915 |
|
Asset retirement obligations, current | 217 |
| | 32 |
| 351 |
| | 378 |
|
Liabilities from risk management activities | 156 |
| | 138 |
| |
Acquisitions payable | | 5 |
| | 489 |
|
Other regulatory liabilities, current | 278 |
| | 26 |
| 337 |
| | 236 |
|
Mirror CWIP | — |
| | 271 |
| |
Other current liabilities | 590 |
| | 374 |
| 868 |
| | 925 |
|
Total current liabilities | 9,129 |
| | 8,961 |
| 13,594 |
| | 12,917 |
|
Long-Term Debt (See accompanying statements) | 24,688 |
| | 20,644 |
| 44,462 |
| | 42,629 |
|
Deferred Credits and Other Liabilities: | | | | | | |
Accumulated deferred income taxes | 12,322 |
| | 11,082 |
| 6,842 |
| | 14,092 |
|
Deferred credits related to income taxes | 187 |
| | 192 |
| 7,256 |
| | 219 |
|
Accumulated deferred investment tax credits | 1,219 |
| | 1,208 |
| |
Accumulated deferred ITCs | | 2,267 |
| | 2,228 |
|
Employee benefit obligations | 2,582 |
| | 2,432 |
| 2,256 |
| | 2,299 |
|
Asset retirement obligations, deferred | 3,542 |
| | 2,168 |
| 4,473 |
| | 4,136 |
|
Unrecognized tax benefits | 370 |
| | 4 |
| |
Accrued environmental remediation | | 389 |
| | 397 |
|
Other cost of removal obligations | 1,162 |
| | 1,215 |
| 2,684 |
| | 2,748 |
|
Other regulatory liabilities, deferred | 254 |
| | 398 |
| 239 |
| | 258 |
|
Other deferred credits and liabilities | 720 |
| | 589 |
| 691 |
| | 880 |
|
Total deferred credits and other liabilities | 22,358 |
| | 19,288 |
| 27,097 |
| | 27,257 |
|
Total Liabilities | 56,175 |
| | 48,893 |
| 85,153 |
| | 82,803 |
|
Redeemable Preferred Stock of Subsidiaries (See accompanying statements) | 118 |
| | 375 |
| 324 |
| | 118 |
|
Redeemable Noncontrolling Interests (See accompanying statements) | 43 |
| | 39 |
| — |
| | 164 |
|
Total Stockholders' Equity (See accompanying statements) | 21,982 |
| | 20,926 |
| 25,528 |
| | 26,612 |
|
Total Liabilities and Stockholders' Equity | $ | 78,318 |
| | $ | 70,233 |
| $ | 111,005 |
| | $ | 109,697 |
|
Commitments and Contingent Matters (See notes) |
| |
|
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 20152017 and 20142016
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | | | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| | | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | | (in millions) | | | (percent of total) | | | (in millions) | | | (percent of total) |
Long-Term Debt: | | | | | | | | | | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | | | | | | | | | | |
Variable rate (3.43% at 1/1/16) due 2042 | | $ | 206 |
| | $ | 206 |
| | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | | | $ | 206 |
| | $ | 206 |
| | | | |
Long-term senior notes and debt — | | | | | | | | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | | Interest Rates | | | | | | | | |
2015 | 0.55% to 5.25% | | — |
| | 2,375 |
| | | | | |
2016 | 1.95% to 5.30% | | 1,360 |
| | 1,360 |
| | | | | |
2017 | 1.30% to 5.90% | | 1,995 |
| | 1,495 |
| | | | | 1.30% to 7.20% | | — |
| | 2,019 |
| | | | |
2018 | 1.50% to 5.40% | | 1,697 |
| | 850 |
| | | | | 1.50% to 5.40% | | 2,402 |
| | 2,403 |
| | | | |
2019 | 2.15% to 5.55% | | 1,176 |
| | 1,175 |
| | | | | 1.85% to 5.55% | | 3,074 |
| | 3,076 |
| | | | |
2020 | 2.38% to 4.75% | | 1,327 |
| | 425 |
| | | | | 2.00% to 4.75% | | 2,273 |
| | 1,326 |
| | | | |
2021 through 2051 | 1.63% to 6.38% | | 11,185 |
| | 10,150 |
| | | | | |
Variable rates (0.77% to 1.17% at 1/1/15) due 2015 | | — |
| | 775 |
| | | | | |
Variable rates (0.76% to 3.50% at 1/1/16) due 2016 | | 1,278 |
| | 450 |
| | | | | |
Variable rates (1.74% at 1/1/16) due 2017 | | 400 |
| | — |
| | | | | |
2021 | | 2.35% to 9.10% | | 2,643 |
| | 2,655 |
| | | | |
2022 | | 1.00% to 8.70% | | 2,016 |
| | 1,378 |
| | | | |
2023 through 2047 | | 1.85% to 7.30% | | 22,142 |
| | 20,369 |
| | | | |
Variable rates (1.82% to 3.75% at 1/1/17) due 2017 | | | — |
| | 461 |
| | | | |
Variable rates (2.29% to 3.05% at 12/31/17) due 2018 | | | 1,420 |
| | 1,520 |
| | | | |
Variable rates (2.04% to 2.18% at 12/31/17) due 2020 | | | 825 |
| | — |
| | | | |
Variable rates (2.55% to 2.79% at 12/31/17) due 2021 | | | 25 |
| | 25 |
| | | | |
Variable rate (3.75% at 1/1/17) due 2032 to 2036 | | | — |
| | 15 |
| | | | |
Total long-term senior notes and debt | | 20,418 |
| | 19,055 |
| | | | | | 36,820 |
| | 35,247 |
| | | | |
Other long-term debt — | | | | | | | | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | | Interest Rates | | | | | | | | |
2019 | 4.55% | | 25 |
| | 25 |
| | | | | 4.55% | | 25 |
| | 25 |
| | | | |
2022 through 2049 | 0.28% to 5.15% | | 1,509 |
| | 1,466 |
| | | | | |
Variable rates (0.03% to 0.04% at 1/1/15) due 2015 | | — |
| | 152 |
| | | | | |
Variable rate (0.22% at 1/1/16) due 2016 | | 4 |
| | 4 |
| | | | | |
Variable rate (0.05% to 0.06% at 1/1/16) due 2017 | | 36 |
| | 36 |
| | | | | |
Variable rate (0.16% at 1/1/16) due 2020 | | 7 |
| | 7 |
| | | | | |
Variable rates (0.01% to 0.27% at 1/1/16) due 2021 to 2053 | | 1,757 |
| | 1,559 |
| | | | | |
2022 | | 2.10% to 2.35% | | 90 |
| | 90 |
| | | | |
2023 through 2049 | | 1.15% to 5.15% | | 1,379 |
| | 1,339 |
| | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | | | 40 |
| | 76 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | | | 65 |
| | 65 |
| | | | |
Variable rates (1.83% to 1.84% at 12/31/17) due 2022 | | | 17 |
| | 17 |
| | | | |
Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053 | | | 1,680 |
| | 1,721 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | | 270 |
| | 270 |
| | | | | | 270 |
| | 270 |
| | | | |
FFB loans — | | | | | | | | | | | | | | | | |
3.00% to 3.86% due 2020 | | 37 |
| | 20 |
| | | | | |
3.00% to 3.86% due 2021 to 2044 | | 2,163 |
| | 1,180 |
| | | | | |
Junior subordinated notes (6.25%) due 2075 | | 1,000 |
| | — |
| | | | | |
2.57% to 3.86% due 2020 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2021 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2022 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2023 to 2044 | | | 2,493 |
| | 2,493 |
| | | | |
First mortgage bonds — | | | | | | | | | |
4.70% due 2019 | | | 50 |
| | 50 |
| | | | |
2.66% to 6.58% due 2023 to 2057 | | | 975 |
| | 575 |
| | | | |
Gas facility revenue bonds — | | | | | | | | | |
Variable rate (1.71% at 12/31/17) due 2022 | | | 47 |
| | 47 |
| | | | |
Variable rate (1.71% at 12/31/17) due 2024 to 2033 | | | 154 |
| | 154 |
| | | | |
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077 | | | 3,570 |
| | 2,350 |
| | | | |
Total other long-term debt | | 6,808 |
| | 4,719 |
| | | | | | 10,987 |
| | 9,404 |
| | | | |
Unamortized fair value adjustment of long-term debt | | | 525 |
| | 578 |
| | | | |
Capitalized lease obligations | | 146 |
| | 159 |
| | | | | | 204 |
| | 136 |
| | | | |
Unamortized debt premium | | 61 |
| | 69 |
| | | | | | 44 |
| | 52 |
| | | | |
Unamortized debt discount | | (36 | ) | | (33 | ) | | | | | | (206 | ) | | (194 | ) | | | | |
Unamortized debt issuance expense | | (241 | ) | | (202 | ) | | | | | | (226 | ) | | (213 | ) | | | | |
Total long-term debt (annual interest requirement — $997 million) | | 27,362 |
| | 23,973 |
| | | | | |
Total long-term debt (annual interest requirement — $1.8 billion) | | Total long-term debt (annual interest requirement — $1.8 billion) | | 48,354 |
| | 45,216 |
| | | | |
Less amount due within one year | | 2,674 |
| | 3,329 |
| | | | | | 3,892 |
| | 2,587 |
| | | | |
Long-term debt excluding amount due within one year | | 24,688 |
| | 20,644 |
| | 52.6 | % | | 49.2 | % | | 44,462 |
| | 42,629 |
| | 63.2 | % | | 61.3 | % |
| | | | | | | | | | | | | | | | |
| | CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2015 and 2014 Southern Company and Subsidiary Companies 2015 Annual Report | | | | | | | | | |
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report | | CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report | | | | | | | | |
| | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | (in millions) | | | (percent of total) | | (in millions) | | | (percent of total) |
Redeemable Preferred Stock of Subsidiaries: | | | | | | | | | | | | | | | | |
Cumulative preferred stock | | | | | | | | | | | | | | | | |
$100 par or stated value — 4.20% to 5.44% | | | | | | | | | | | | | | | | |
Authorized — 20 million shares | | | | | | | | | | | | | | | | |
Outstanding — 1 million shares | | 81 |
| | 81 |
| | | | | | 324 |
| | 81 |
| | | | |
$1 par value — | | | | | | | | | |
$1 par value — 5.83% | | | | | | | | | |
Authorized — 28 million shares | | | | | | | | | | | | | | | | |
Outstanding — $25 stated value | | 37 |
| | 294 |
| | | | | |
— 2015: 5.83% — 2 million shares | | | | | | | | | |
— 2014: 5.20% to 5.83% — 12 million shares | | | | | | | | | |
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $6 million) | | | 118 |
| | 375 |
| | 0.3 |
| | 0.9 |
| |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares: $25 stated value | | | — |
| | 37 |
| | | | |
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $16 million) | | | 324 |
| | 118 |
| | 0.5 |
| | 0.2 |
|
Redeemable Noncontrolling Interests | | 43 |
| | 39 |
| | 0.1 |
| | 0.1 |
| | — |
| | 164 |
| | — |
| | 0.2 |
|
Common Stockholders' Equity: | | | | | | | | | | | | | | | | |
Common stock, par value $5 per share — | | 4,572 |
| | 4,539 |
| | | | | | 5,038 |
| | 4,952 |
| | | | |
Authorized — 1.5 billion shares | | | | | | | | | | | | | | | | |
Issued — 2015: 915 million shares | | | | | | | | | |
— 2014: 909 million shares | | | | | | | | | |
Treasury — 2015: 3.4 million shares | | | | | | | | | |
— 2014: 0.7 million shares | | | | | | | | | |
Issued — 2017: 1.0 billion shares | | | | | | | | | |
— 2016: 991 million shares | | | | | | | | | |
Treasury — 2017: 0.9 million shares | | | | | | | | | |
— 2016: 0.8 million shares | | | | | | | | | |
Paid-in capital | | 6,282 |
| | 5,955 |
| | | | | | 10,469 |
| | 9,661 |
| | | | |
Treasury, at cost | | (142 | ) | | (26 | ) | | | | | | (36 | ) | | (31 | ) | | | | |
Retained earnings | | 10,010 |
| | 9,609 |
| | | | | | 8,885 |
| | 10,356 |
| | | | |
Accumulated other comprehensive loss | | | (130 | ) | | (128 | ) | | | | | | | (189 | ) | | (180 | ) | | | | |
Total common stockholders' equity | | | 20,592 |
| | 19,949 |
| | 44.0 |
| | 47.5 |
| | | 24,167 |
| | 24,758 |
| | 34.4 |
| | 35.6 |
|
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests: | | | | | | | | | | | | | | | | |
Non-cumulative preferred stock | | | | | | | | | | | | | | | | |
$25 par value — 6.00% to 6.13% | | | | | | | | | | | | | | | | |
Authorized — 60 million shares | | | | | | | | | | | | | | | | |
Outstanding — 2 million shares | | 45 |
| | 45 |
| | | | | |
Preference stock | | | | | | | | | |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares | | | — |
| | 45 |
| | | | |
Non-cumulative preference stock | | | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | | | |
Authorized — 65 million shares | | | | | | | | | | | | | | | | |
Outstanding — $1 par value | | 196 |
| | 343 |
| | | | | |
— 2015: 6.45% to 6.50% — 8 million shares (non-cumulative) | | | | | | | | | |
— 2014: 5.63% to 6.50% — 14 million shares (non-cumulative) | | | | | | | | | |
Outstanding — $100 par or stated value | | 368 |
| | 368 |
| | | | | |
— 5.60% to 6.50% — 4 million shares (non-cumulative) | | | | | | | | | |
Noncontrolling Interests | | 781 |
| | 221 |
| | | | | |
Total preferred and preference stock of subsidiaries and noncontrolling interests (annual dividend requirement — $39 million) | | 1,390 |
| | 977 |
| | 3.0 |
| | 2.3 |
| |
Outstanding — 2017: no shares | | | — |
| | 196 |
| | | | |
— 2016: 8 million shares | | | | | | | | | |
$100 par or stated value — 5.60% to 6.50% | | | | | | | | | |
Outstanding — 2017: no shares | | | — |
| | 368 |
| | | | |
— 2016: 4 million shares | | | | | | | | | |
Noncontrolling interests | | | 1,361 |
| | 1,245 |
| | | | |
Total preferred and preference stock of subsidiaries and noncontrolling interests | | | 1,361 |
| | 1,854 |
| | 1.9 |
| | 2.7 |
|
Total stockholders' equity | | | 21,982 |
| | 20,926 |
| | | | | | | 25,528 |
| | 26,612 |
| | | | |
Total Capitalization | | | $ | 46,831 |
| | $ | 41,984 |
| | 100.0 | % | | 100.0 | % | | | $ | 70,314 |
| | $ | 69,523 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | Southern Company Common Stockholders' Equity | | | | | Southern Company Common Stockholders' Equity | | | | |
| Number of Common Shares | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Preferred and Preference Stock of Subsidiaries | | Noncontrolling Interests | | Number of Common Shares | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Preferred and Preference Stock of Subsidiaries | | Noncontrolling Interests | |
| Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | Total | Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | Total |
| (in thousands) | | (in millions) | (in thousands) | | (in millions) |
Balance at December 31, 2012 | 877,803 |
| | (10,035) | | $ | 4,389 |
| | $ | 4,855 |
| | $ | (450 | ) | | $ | 9,626 |
| | $ | (123 | ) | | $ | 707 |
| | $ | — |
| $ | 19,004 |
| |
Consolidated net income attributable to Southern Company | — |
| | — | | — |
| | — |
| | — |
| | 1,644 |
| | — |
| | — |
| | — |
| 1,644 |
| |
Other comprehensive income (loss) | — |
| | — | | — |
| | — |
| | — |
| | — |
| | 48 |
| | — |
| | — |
| 48 |
| |
Stock issued | 14,930 |
| | 4,443 | | 72 |
| | 441 |
| | 203 |
| | — |
| | — |
| | 49 |
| | — |
| 765 |
| |
Stock-based compensation | — |
| | — | | — |
| | 65 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 65 |
| |
Cash dividends of $2.0125 per share | — |
| | — | | — |
| | — |
| | — |
| | (1,762 | ) | | — |
| | — |
| | — |
| (1,762 | ) | |
Other | — |
| | (55) | | — |
| | 1 |
| | (3 | ) | | 2 |
| | — |
| | — |
| | — |
| — |
| |
Balance at December 31, 2013 | 892,733 |
| | (5,647) | | 4,461 |
| | 5,362 |
| | (250 | ) | | 9,510 |
| | (75 | ) | | 756 |
| | — |
| 19,764 |
| |
Consolidated net income attributable to Southern Company | — |
| | — | | — |
| | — |
| | — |
| | 1,963 |
| | — |
| | — |
| | — |
| 1,963 |
| |
Other comprehensive income (loss) | — |
| | — | | — |
| | — |
| | — |
| | — |
| | (53 | ) | | — |
| | — |
| (53 | ) | |
Stock issued | 15,769 |
| | 4,996 | | 78 |
| | 501 |
| | 227 |
| | — |
| | — |
| | — |
| | — |
| 806 |
| |
Stock-based compensation | — |
| | — | | — |
| | 86 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 86 |
| |
Cash dividends of $2.0825 per share | — |
| | — | | — |
| | — |
| | — |
| | (1,866 | ) | | — |
| | — |
| | — |
| (1,866 | ) | |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 221 |
| 221 |
| |
Net income (loss) attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | (2 | ) | |
Other | — |
| | (74) | | — |
| | 6 |
| | (3 | ) | | 2 |
| | — |
| | — |
| | 2 |
| 7 |
| |
Balance at December 31, 2014 | 908,502 |
| | (725) | | 4,539 |
| | 5,955 |
| | (26 | ) | | 9,609 |
| | (128 | ) | | 756 |
| | 221 |
| 20,926 |
| 908,502 |
| | (725 | ) | | $ | 4,539 |
| | $ | 5,955 |
| | $ | (26 | ) | | $ | 9,609 |
| | $ | (128 | ) | | $ | 756 |
| | $ | 221 |
| $ | 20,926 |
|
Consolidated net income attributable to Southern Company | — |
| | — | | — |
| | — |
| | — |
| | 2,367 |
| | — |
| | — |
| | — |
| 2,367 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 2,367 |
| | — |
| | — |
| | — |
| 2,367 |
|
Other comprehensive income (loss) | — |
| | — | | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| (2 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| (2 | ) |
Stock issued | 6,571 |
| | (2,599) | | 33 |
| | 223 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 256 |
| 6,571 |
| | (2,599 | ) | | 33 |
| | 223 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 256 |
|
Stock-based compensation | — |
| | — | | — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 100 |
| — |
| | — |
| | — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 100 |
|
Stock repurchased, at cost | — |
| | — |
| | — |
| | — |
| | (115 | ) | | — |
| | — |
| | — |
| | — |
| (115 | ) | — |
| | — |
| | — |
| | — |
| | (115 | ) | | — |
| | — |
| | — |
| | — |
| (115 | ) |
Cash dividends of $2.1525 per share | — |
| | — | | — |
| | — |
| | — |
| | (1,959 | ) | | — |
| | — |
| | — |
| (1,959 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (1,959 | ) | | — |
| | — |
| | — |
| (1,959 | ) |
Preference stock redemptions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (150 | ) | | — |
| (150 | ) | |
Preference stock redemption | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (150 | ) | | — |
| (150 | ) |
Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| 567 |
|
Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | (18 | ) |
Net loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| 12 |
|
Other | | — |
| | (28 | ) | | — |
| | 4 |
| | (1 | ) | | (7 | ) | | — |
| | 3 |
| | (1 | ) | (2 | ) |
Balance at December 31, 2015 | | 915,073 |
| | (3,352 | ) | | 4,572 |
| | 6,282 |
| | (142 | ) | | 10,010 |
| | (130 | ) | | 609 |
| | 781 |
| 21,982 |
|
Consolidated net income attributable to Southern Company | | — |
| | — |
| | — |
| | — |
| | — |
| | 2,448 |
| | — |
| | — |
| | — |
| 2,448 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (50 | ) | | — |
| | — |
| (50 | ) |
Stock issued | | 76,140 |
| | 2,599 |
| | 380 |
| | 3,263 |
| | 115 |
| | — |
| | — |
| | — |
| | — |
| 3,758 |
|
Stock-based compensation | | — |
| | — |
| | — |
| | 120 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 120 |
|
Cash dividends of $2.2225 per share | | — |
| | — |
| | — |
| | — |
| | — |
| | (2,104 | ) | | — |
| | — |
| | — |
| (2,104 | ) |
Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| 618 |
|
Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | (57 | ) |
Purchase of membership interests from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | (129 | ) |
Net income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| 32 |
|
Other | | — |
| | (66 | ) | | — |
| | (4 | ) | | (4 | ) | | 2 |
| | — |
| | — |
| | — |
| (6 | ) |
Balance at December 31, 2016 | | 991,213 |
| | (819 | ) | | 4,952 |
| | 9,661 |
| | (31 | ) | | 10,356 |
| | (180 | ) | | 609 |
| | 1,245 |
| 26,612 |
|
Consolidated net income attributable to Southern Company | | — |
| | — |
| | — |
| | — |
| | — |
| | 842 |
| | — |
| | — |
| | — |
| 842 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (9 | ) | | — |
| | — |
| (9 | ) |
Stock issued | | 17,319 |
| | — |
| | 86 |
| | 707 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 793 |
|
Stock-based compensation | | — |
| | — |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 105 |
|
Cash dividends of $2.3000 per share | | — |
| | — |
| | — |
| | — |
| | — |
| | (2,300 | ) | | — |
| | — |
| | — |
| (2,300 | ) |
Preferred and preference stock redemptions | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (609 | ) | | — |
| (609 | ) |
Contributions from noncontrolling interests | — |
| | — | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| 567 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | (18 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | (122 | ) |
Net income attributable to noncontrolling interests | — |
| | — | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| 12 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| 44 |
|
Reclassification from redeemable noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| 114 |
|
Other | — |
| | (28) | | — |
| | 4 |
| | (1 | ) | | (7 | ) | | — |
| | 3 |
| | (1 | ) | (2 | ) | — |
| | (110 | ) | | — |
| | (4 | ) | | (5 | ) | | (13 | ) | | — |
| | — |
| | 1 |
| (21 | ) |
Balance at December 31, 2015 | 915,073 |
| | (3,352) | | $ | 4,572 |
| | $ | 6,282 |
| | $ | (142 | ) | | $ | 10,010 |
| | $ | (130 | ) | | $ | 609 |
| | $ | 781 |
| $ | 21,982 |
| |
Balance at December 31, 2017 | | 1,008,532 |
| | (929 | ) | | $ | 5,038 |
| | $ | 10,469 |
| | $ | (36 | ) | | $ | 8,885 |
| | $ | (189 | ) | | $ | — |
| | $ | 1,361 |
| $ | 25,528 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 20152017 Annual Report
Index to the Notes to Financial Statements
|
| | |
Note | | Page |
1 | | |
2 | | |
3 | | |
4 | | |
5 | | |
6 | | |
7 | | |
8 | | |
9 | | |
10 | | |
11 | | |
12 | | |
13 | | |
14 | | |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, SouthernLINC Wireless,Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cableoptics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants.plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain of theirother subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs.PSCs or other applicable state regulatory agencies. As such, each of the company'sconsolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by their respective commissions.relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows.
In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period.error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers revises(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition effectivewith a five-step model for fiscal years beginning after December 15, 2017. Southern Company continues to evaluate the requirements of ASC 606.recognizing and measuring revenue from contracts with customers. The ultimate impactunderlying principle of the new standard has not yet been determined.is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – ImputationMost of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requiresSouthern Company's revenue, including energy provided to customers, is from tariff offerings that debt issuance costs related toprovide electricity or natural gas without a recognized debt liability be presented in the balance sheetdefined contractual term, as a direct deduction from the carrying amount of that debt liabilitywell as longer-term contractual commitments, including PPAs and is effective for fiscal years beginning after December 15, 2015. As permitted, non-derivative natural gas asset management and optimization arrangements.
Southern Company elected to early adopthas completed the guidance asevaluation of December 31, 2015all revenue streams and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $202 million as of December 31, 2014. These debt issuance costs were previously presented within unamortized debt issuance expense. Other than the reclassification,determined that the adoption of ASU 2015-03 didASC 606 will not have an impact onchange the resultscurrent timing of operations, cash flows, or financial conditionrevenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of Southern Company. See Notes 6ASC 606 and, 10 for disclosures impacted by ASU 2015-03.therefore, will be
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, Southern Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current presentation.guidance. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of Southern Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07.ASC 606 did not result in a cumulative-effect adjustment.
Leases
On November 20, 2015,In February 2016, the FASB issued ASU No. 2015-17,2016-02, Income TaxesLeases (Topic 740): Balance Sheet Classification of Deferred Taxes 842)( (ASU 2016-02). ASU 2015-17), which simplifies2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of deferred income taxes.expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In March 2016, including interim periods within that reporting period. As permitted,the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to early adopt the guidance in 2016 and reflect the related adjustments as of December 31, 2015 and applied its provisions retrospectivelyJanuary 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts.recognize forfeitures as they occur. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million, with $488 million to non-current accumulated deferred income taxes and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have ana material impact on the results of operations, financial position, or cash flows or financial condition of Southern Company. See NoteNotes 5 and 8 for disclosures impacted by ASU 2015-17.2016-09.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Regulatory Assets and Liabilities
The traditional electric operating companies and natural gas distribution utilities are subject to the provisions of the FASB in accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
| | | 2015 |
| | 2014 |
| | Note | 2017 | | 2016 | | Note |
| (in millions) | | (in millions) | |
Retiree benefit plans | $ | 3,440 |
| | $ | 3,469 |
| | (a,n) | $ | 3,931 |
| | $ | 3,959 |
| | (a,n) |
Asset retirement obligations-asset | | 1,133 |
| | 1,080 |
| | (b,n) |
Deferred income tax charges | 1,514 |
| | 1,458 |
| | (b) | 814 |
| | 1,590 |
| | (b,p) |
Asset retirement obligations-asset | 481 |
| | 119 |
| | (b,n) | |
Other regulatory assets | 299 |
| | 275 |
| | (k) | |
Loss on reacquired debt | 248 |
| | 267 |
| | (c) | |
Fuel-hedging-asset | 225 |
| | 202 |
| | (d,n) | |
Kemper IGCC regulatory assets | 216 |
| | 148 |
| | (h) | |
Vacation pay | 178 |
| | 177 |
| | (f,n) | |
Deferred PPA charges | 163 |
| | 185 |
| | (e,n) | |
Environmental remediation-asset | | 511 |
| | 491 |
| | (j,n) |
Property damage reserves-asset | | 333 |
| | 206 |
| | (i) |
Under recovered regulatory clause revenues | 142 |
| | 157 |
| | (g) | 317 |
| | 273 |
| | (g) |
Remaining net book value of retired assets | 283 |
| | 44 |
| | (o) | 306 |
| | 351 |
| | (o) |
Environmental remediation-asset | 78 |
| | 64 |
| | (j,n) | |
Property damage reserves-asset | 92 |
| | 98 |
| | (i) | |
Nuclear outage | 88 |
| | 99 |
| | (g) | |
Loss on reacquired debt | | 223 |
| | 243 |
| | (c) |
Vacation pay | | 183 |
| | 182 |
| | (f,n) |
Long-term debt fair value adjustment | | 138 |
| | 155 |
| | (d) |
Deferred PPA charges | | 119 |
| | 141 |
| | (e,n) |
Kemper County energy facility | | 88 |
| | 201 |
| | (h) |
Other regulatory assets | | 511 |
| | 487 |
| | (k) |
Deferred income tax credits | | (7,261 | ) | | (219 | ) | | (b,p) |
Other cost of removal obligations | (1,177 | ) | | (1,229 | ) | | (b) | (2,684 | ) | | (2,774 | ) | | (b) |
Over recovered regulatory clause revenues | (261 | ) | | (48 | ) | | (g) | (155 | ) | | (203 | ) | | (g) |
Deferred income tax credits | (187 | ) | | (192 | ) | | (b) | |
Property damage reserves-liability | (178 | ) | | (181 | ) | | (l) | (135 | ) | | (177 | ) | | (l) |
Asset retirement obligations-liability | (45 | ) | | (130 | ) | | (b,n) | |
Other regulatory liabilities | (35 | ) | | (47 | ) | | (m) | (266 | ) | | (120 | ) | | (m) |
Mirror CWIP | — |
| | (271 | ) | | (h) | |
Total regulatory assets (liabilities), net | $ | 5,564 |
| | $ | 4,664 |
| | $ | (1,894 | ) | | $ | 5,866 |
| |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(b) | Asset retirement and other cost of removal assets and liabilitiesobligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 7080 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2015, other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with Georgia Power's 2013 ARP. |
| |
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. |
| |
(d) | RecordedRecovered over the remaining life of the underlying hedged purchase contracts,original debt issuances, which generally do not exceed fiverange up to 21 years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause.For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas." |
| |
(e) | Recovered over the life of the PPA for periods up to eightsix years. |
| |
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding 10 years. |
| |
(h) | Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years, respectively. For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle"Kemper County Energy Facility – Rate Recovery of – Kemper IGCC Costs – Regulatory Assets and Liabilities.Settlement Agreement." |
| |
(i) | RecordedPrevious under-recovery as of December 2013 is recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding six years.Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information. |
| |
(j) | Recovered through the environmental cost recovery clausemechanisms when the remediation is performed or the work is performed. |
| |
(k) | Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building leases, closure of Plant Scholz ash pond, Plant Daniel Units 3 and 4 regulatory assets,generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 1550 years. |
| |
(l) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. |
| |
(m) | Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 1520 years. |
| |
(n) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(o) | Amortized as approved by the appropriate state PSCs over periods generally up to 48 years. |
| |
(p) | As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not exceeding 11 years.subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional information. |
In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Power,are to be reflected in rates. See Note 3 under " "Retail Regulatory Matters – Alabama Power," " – Georgia Power," "Retail Regulatory Matters" – Gulf Power "and "Integrated Coal Gasification Combined Cycle"," and " – Southern Company Gas" and "Kemper County Energy Facility" for additional information.
Revenues
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. ElectricRetail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. RevenuesFor the traditional electric operating companies, revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months. Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs.
Southern Company's electric utility subsidiaries and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal production tax credits (PTC),PTCs, which are recorded to income tax expense based on KWH production.
Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 20152017 and will be carried forward and utilized in future years. In addition, Southern Company has subsidiaries with various stateis expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which couldwould result in net state income tax benefits in the future, if utilized. See Note 5 to the financial statementsunder "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss" for additional information.
Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized"Unrecognized Tax Benefits"Benefits" for additional information.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Electric utilities: | | | | |
Generation | $ | 41,648 |
| | $ | 37,892 |
| $ | 51,279 |
| | $ | 48,836 |
|
Transmission | 10,544 |
| | 9,884 |
| 11,562 |
| | 11,156 |
|
Distribution | 17,670 |
| | 17,123 |
| 19,239 |
| | 18,418 |
|
General | 4,377 |
| | 4,198 |
| 4,276 |
| | 4,629 |
|
Plant acquisition adjustment | 123 |
| | 123 |
| 126 |
| | 126 |
|
Electric utility plant in service | | 86,482 |
| | 83,165 |
|
Natural gas distribution utilities: | | | | |
Transportation and distribution | | 13,078 |
| | 11,996 |
|
Utility plant in service | 74,362 |
| | 69,220 |
| 99,560 |
| | 95,161 |
|
Information technology equipment and software | 222 |
| | 244 |
| 752 |
| | 544 |
|
Communications equipment | 418 |
| | 439 |
| 456 |
| | 424 |
|
Storage facilities | | 1,598 |
| | 1,463 |
|
Other | 116 |
| | 110 |
| 1,176 |
| | 824 |
|
Other plant in service | 756 |
| | 793 |
| |
Total other plant in service | | 3,982 |
| | 3,255 |
|
Total plant in service | $ | 75,118 |
| | $ | 70,013 |
| $ | 103,542 |
| | $ | 98,416 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded incosts. In accordance with specifictheir respective state PSC orders.orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle. The refueling cycles for Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle Units 1 and 2 rangecycle, which ranges from 18 to 24 months, depending on the unit.months.
Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below:
| |
| Asset Balances at December 31, | Asset Balances at December 31, |
| 2015 |
| 2014 | 2017 |
| 2016 |
| (in millions) | (in millions) |
Office building | $ | 61 |
|
| $ | 61 |
| |
Nitrogen plant | 83 |
|
| 83 |
| |
Office buildings | | $ | 216 |
|
| $ | 61 |
|
Nitrogen plant(*) | | — |
|
| 83 |
|
Computer-related equipment | 61 |
|
| 60 |
| 51 |
|
| 63 |
|
Gas pipeline | 6 |
|
| 6 |
| 6 |
|
| 6 |
|
Less: Accumulated amortization | (59 | ) |
| (49 | ) | (72 | ) |
| (69 | ) |
Balance, net of amortization | $ | 152 |
|
| $ | 161 |
| $ | 201 |
|
| $ | 144 |
|
| |
(*) | Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. |
The amount of non-cash property additions recognized for the years ended December 31, 20152017, 20142016, and 20132015 was $985 million, $1.3 billion, and $844 million,$528 million, and $411 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2017, 2016, and 2015 2014,was $162 million, $18 million, and 2013 was $13 million, $25 million,respectively.
NOTES (continued)
Southern Company and $107 million, respectively.Subsidiary Companies 2017 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.0%2.9% in 2017 and 2015, 3.1%3.0% in 2014,each of 2016 and 3.3% in 20132015. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and the FERCfederal regulatory agencies for the traditional electric operating companies.companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $23.7$30.8 billion and $23.529.3 billion at December 31, 20152017 and 20142016, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets. Cost, net of salvage value, of these
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
assets is depreciated on an hours or starts units-of-production basis. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million, respectively.
Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, Georgia Power amortized approximately $31 million in 2013 and $14 million in each ofannually from 2014 and 2015through 2016 of its remaining regulatory liability related to other cost of removal obligations.
See Note 3 under "Retail "Regulatory Matters – Alabama Power – Cost of Removal Accounting Order" and "– Gulf Power – Retail Base Rate CaseCases" for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability by Alabama Power and Gulf Power, respectively.liability.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from threetwo to 2565 years. Accumulated depreciation for other plant in service totaled $510$673 million and $533550 million at December 31, 20152017 and 20142016, respectively.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO)AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from the variousits state PSCsPSC or applicable state regulatory agency allowing the continued accrual or recovery of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset.
The liability for AROs primarily relates to the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2 – and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17,in 2015 (CCR Rule), principally ash ponds.ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore,as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning""Nuclear Decommissioning" herein for additional information on amounts included in rates.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of the AROs included in the balance sheets are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Balance at beginning of year | $ | 2,201 |
| | $ | 2,018 |
| $ | 4,514 |
| | $ | 3,759 |
|
Liabilities incurred | 662 |
| | 18 |
| 16 |
| | 66 |
|
Liabilities settled | (37 | ) | | (17 | ) | (177 | ) | | (171 | ) |
Accretion | 115 |
| | 102 |
| 179 |
| | 162 |
|
Cash flow revisions | 818 |
| | 80 |
| 292 |
| | 698 |
|
Balance at end of year | $ | 3,759 |
| | $ | 2,201 |
| $ | 4,824 |
| | $ | 4,514 |
|
TheIn 2017 and 2016, the increases in cash flow revisions are primarily related to changes in closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities incurred and cash flow revisions in 2015settled are primarily relaterelated to an increase in AROs associated with facilities impacted by the CCR Rule and Georgia Power's updated nuclear decommissioning study. ash pond closure activity.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 20152017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place or by other methods.closure. As further analysis is performed including evaluation of the expected
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the traditional electric operating companies expect towill continue to periodically update these estimates.
The cash flow revisions in 2014 are primarily related to Alabama Power's and SEGCO's AROs associated with asbestos at their steam generation facilities.cost estimates as necessary.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 20152017 and 20142016, approximately $76 million and $51$56 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $78$77 million and $52$58 million at December 31, 20152017 and 2014,2016, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
At December 31, 2015,2017, investment securities in the Funds totaled $1.5$1.8 billion, consisting of equity securities of $817 million,$1.1 billion, debt securities of $654$725 million, and $38$47 million of other securities. At December 31, 2014,2016, investment securities in the Funds totaled $1.5$1.6 billion,, consisting of equity securities of $886$878 million,, debt securities of $638$685 million,, and $19$41 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the securities lending pool.program.
Sales of the securities held in the Funds resulted in cash proceeds of $0.8 billion, $1.2 billion, and $1.4 billion $913 million,in 2017, 2016, and $1.0 billion in 2015,, 2014, and 2013, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $233 million, which included $181 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million, which included $48 million related to unrealized losses on securities held in the Funds at
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 31, 2016. For 2015,, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $11 million, which included $83 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $98 million, which included $19 million related to unrealized gains and losses on securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million, which included $119 million related to unrealized gains on securities held in the Funds at December 31, 2013. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
For Alabama Power, amountsapproximately $18 million and $19 million at December 31, 2017 and 2016, respectively, previously recorded in internal reserves areis being transferred into the Funds over periodsthrough 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
At December 31, 20152017 and 20142016, the accumulated provisions for the external decommissioning trust funds were as follows:
| | | External Trust Funds | | Internal Reserves | | Total | External Trust Funds |
| 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| 2017 | | 2016 |
| (in millions) | (in millions) |
Plant Farley | $ | 734 |
| | $ | 754 |
| | $ | 20 |
| | $ | 21 |
| | $ | 754 |
| | $ | 775 |
| $ | 902 |
| | $ | 790 |
|
Plant Hatch | 487 |
| | 496 |
| | — |
| | — |
| | 487 |
| | 496 |
| 583 |
| | 511 |
|
Plant Vogtle Units 1 and 2 | 288 |
| | 293 |
| | — |
| | — |
| | 288 |
| | 293 |
| 346 |
| | 303 |
|
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 20152017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:
|
| | | | | | | | | | | |
| Plant Farley | | Plant Hatch | | Plant Vogtle Units 1 and 2 |
Decommissioning periods: | | | | | |
Beginning year | 2037 |
| | 2034 |
| | 2047 |
|
Completion year | 2076 |
| | 2075 |
| | 2079 |
|
| (in millions) |
Site study costs: | | | | | |
Radiated structures | $ | 1,362 |
| | $ | 678 |
| | $ | 568 |
|
Spent fuel management | — |
| | 160 |
| | 147 |
|
Non-radiated structures | 80 |
| | 64 |
| | 89 |
|
Total site study costs | $ | 1,442 |
| | $ | 902 |
| | $ | 804 |
|
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs.costs in Georgia Power's 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Allowance for Funds Used During Construction and Interest Capitalized
In accordance with regulatory treatment,The traditional electric operating companies and certain of the traditional operating companiesnatural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes, were as a percentage of net income, was 25.5%, 11.4%, and 12.8% for 2017, 16.0%2016, and 15.0% of net income for 2015, 2014, and 2013, respectively.
Cash payments for interest totaled $1.7 billion, $1.1 billion, and $809 million $732 million,in 2017, 2016, and $759 million in 2015, 2014, and 2013, respectively, net of amounts capitalized of $124$89 million, $111$125 million, and $92124 million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Impairment of Long-Lived Assets and Intangibles
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See "Leveraged Leases" herein and Note 3 under "Other Matters" and "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
Goodwill and Other Intangible Assets and Liabilities
Southern Company's goodwill and other intangible assets and liabilities primarily relate to Southern Company's 2016 acquisitions of PowerSecure and Southern Company Gas. See Note 12 under "Southern Company – Acquisition of PowerSecure" and " – Merger with Southern Company Gas" for additional information. Also see Note 12 under "Southern Power" for additional information regarding other intangible assets related to Southern Power's PPA fair value adjustments.
At December 31, 2017 and 2016, goodwill was $6.3 billion. Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company evaluated its goodwill in the fourth quarter 2017 and determined that no impairment was required.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | At December 31, 2017 | | At December 31, 2016 |
| Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | (in millions) | | (in millions) |
Other intangible assets subject to amortization: | | | | | | | | |
Customer relationships | 11-26 years | $ | 288 |
| $ | (83 | ) | $ | 205 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
Trade names | 5-28 years | 159 |
| (17 | ) | 142 |
| | 158 |
| (5 | ) | 153 |
|
Storage and transportation contracts | 1-5 years | 64 |
| (34 | ) | 30 |
| | 64 |
| (2 | ) | 62 |
|
PPA fair value adjustments | 10-20 years | 456 |
| (47 | ) | 409 |
| | 456 |
| (22 | ) | 434 |
|
Other | 1-12 years | 17 |
| (5 | ) | 12 |
| | 11 |
| (1 | ) | 10 |
|
Total other intangible assets subject to amortization | | $ | 984 |
| $ | (186 | ) | $ | 798 |
|
| $ | 957 |
| $ | (62 | ) | $ | 895 |
|
Other intangible assets not subject to amortization: | | | | | | | | |
Federal Communications Commission licenses | | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
Total other intangible assets | | $ | 1,059 |
| $ | (186 | ) | $ | 873 |
|
| $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
Amortization associated with other intangible assets in 2017, 2016, and 2015 totaled $124 million, $50 million, and $3 million, respectively.
As of December 31, 2017, the estimated amortization associated with other intangible assets for the next five years is as follows:
|
| | | |
| Amortization |
| (in millions) |
2018 | $ | 95 |
|
2019 | 77 |
|
2020 | 65 |
|
2021 | 56 |
|
2022 | 51 |
|
Included in other deferred credits and liabilities on the balance sheet is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at Southern Company Gas. At December 31, 2017, the accumulated amortization of these intangible liabilities was $50 million. The remaining estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: |
| | | |
| Amortization |
| (in millions) |
2018 | $ | 24 |
|
2019 | 17 |
|
Storm Damage Reserves
Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $41 million in 2017 and $40 million $40 million,in each of 2016 and $28 million in 2015, 2014, and 2013, respectively.2015. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2015, 2014,2017, 2016, and 2013,2015, there were no such additional accruals. See Note 3 under "Retail "Regulatory Matters – Alabama Power – Rate NDR"NDR" and "Retail
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
"Regulatory Matters – Georgia Power – Storm Damage Recovery"Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively.
Leveraged Leases
A subsidiary of Southern CompanyHoldings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. TheSouthern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:
| | | 2015 |
| | 2014 |
| 2017 | | 2016 |
| (in millions) | (in millions) |
Net rentals receivable | $ | 1,487 |
| | $ | 1,495 |
| $ | 1,498 |
| | $ | 1,481 |
|
Unearned income | (732 | ) | | (752 | ) | (723 | ) | | (707 | ) |
Investment in leveraged leases | 755 |
| | 743 |
| 775 |
| | 774 |
|
Deferred taxes from leveraged leases | (303 | ) | | (299 | ) | (252 | ) | | (309 | ) |
Net investment in leveraged leases | $ | 452 |
| | $ | 444 |
| $ | 523 |
| | $ | 465 |
|
A summary of the components of income from the leveraged leases follows:
|
| | | | | | | | | | | |
| 2015 |
| | 2014 |
| | 2013 |
|
| (in millions) |
Pretax leveraged lease income (loss) | $ | 20 |
| | $ | 24 |
| | $ | (5 | ) |
Income tax expense | (7 | ) | | (9 | ) | | 2 |
|
Net leveraged lease income (loss) | $ | 13 |
| | $ | 15 |
| | $ | (3 | ) |
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Pretax leveraged lease income | $ | 25 |
| | $ | 25 |
| | $ | 20 |
|
Net impact of Tax Reform Legislation | 48 |
| | — |
| | — |
|
Income tax expense | (9 | ) | | (9 | ) | | (7 | ) |
Net leveraged lease income | $ | 64 |
| | $ | 16 |
| | $ | 13 |
|
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances.allowances of the electric utilities. Fuel is chargedrecorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Natural Gas for Sale
The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
Financial Instruments
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statementstatements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.
The Company does not offsetoffsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 20152017, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.
Southern Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | | | | | | | |
| Qualifying Hedges | | Marketable Securities | | Pension and Other Postretirement Benefit Plans | | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2014 | $ | (41 | ) | | $ | — |
| | $ | (87 | ) | | $ | (128 | ) |
Current period change | (7 | ) | | — |
| | 5 |
| | (2 | ) |
Balance at December 31, 2015 | $ | (48 | ) | | $ | — |
| | $ | (82 | ) | | $ | (130 | ) |
|
| | | | | | | | | | | |
| Qualifying Hedges | | Pension and Other Postretirement Benefit Plans | | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | (115 | ) | | $ | (65 | ) | | $ | (180 | ) |
Current period change | (4 | ) | | (5 | ) | | (9 | ) |
Balance at December 31, 2017 | $ | (119 | ) | | $ | (70 | ) | | $ | (189 | ) |
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees.employees, with the exception of employees at Southern Company Gas and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016.2018. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2016,2018, no other postretirement trust contributions are expectedexpected.
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to total approximately $14 million.new employees and reopened to all non-union employees on January 1, 2018. This qualified pension plan is funded in accordance with requirements of ERISA. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
| | Assumptions used to determine net periodic costs: | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Pension plans | | | | | | | | | | |
Discount rate – benefit obligations | | 4.40 | % | | 4.58 | % | | 4.17 | % |
Discount rate – interest costs | 4.17 | % | | 5.02 | % | | 4.26 | % | 3.77 |
| | 3.88 |
| | 4.17 |
|
Discount rate – service costs | 4.48 |
| | 5.02 |
| | 4.26 |
| 4.81 |
| | 4.98 |
| | 4.48 |
|
Expected long-term return on plan assets | 8.20 |
| | 8.20 |
| | 8.20 |
| 7.92 |
| | 8.16 |
| | 8.20 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
| 4.37 |
| | 4.37 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | | | | | | |
Discount rate – benefit obligations | | 4.23 | % | | 4.38 | % | | 4.04 | % |
Discount rate – interest costs | 4.04 | % | | 4.85 | % | | 4.05 | % | 3.54 |
| | 3.66 |
| | 4.04 |
|
Discount rate – service costs | 4.39 |
| | 4.85 |
| | 4.05 |
| 4.64 |
| | 4.85 |
| | 4.39 |
|
Expected long-term return on plan assets | 6.97 |
| | 7.15 |
| | 7.13 |
| 6.84 |
| | 6.66 |
| | 6.97 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
| 4.37 |
| | 4.37 |
| | 3.59 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
| | Assumptions used to determine benefit obligations: | 2015 |
| 2014 | 2017 |
| 2016 |
Pension plans |
|
|
|
|
|
|
Discount rate | 4.67 | % |
| 4.17 | % | 3.80 | % |
| 4.40 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.32 |
|
| 4.37 |
|
Other postretirement benefit plans |
|
|
|
|
|
|
Discount rate | 4.51 | % |
| 4.04 | % | 3.68 | % |
| 4.23 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.32 |
|
| 4.37 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seveneight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension and other postretirement benefit plans by approximately $191 million and $35 million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 20152017 were as follows:
| | | | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | | 6.50 | % | | 4.50 | % | | 2024 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | | 5.50 |
| | 4.50 |
| | 2024 | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | | 10.00 |
| | 4.50 |
| | 2025 | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 20152017 as follows:
| | | 1 Percent Increase | | 1 Percent Decrease | 1 Percent Increase | | 1 Percent Decrease |
| (in millions) | (in millions) |
Benefit obligation | $ | 119 |
| | $ | (102 | ) | $ | 132 |
| | $ | 113 |
|
Service and interest costs | 4 |
| | (4 | ) | 4 |
| | 3 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Pension Plans
The total accumulated benefit obligation for the pension plans was $9.6$12.6 billion at December 31, 20152017 and $10.011.3 billion at December 31, 20142016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 10,909 |
| | $ | 8,863 |
| $ | 12,385 |
| | $ | 10,542 |
|
Acquisitions | | — |
| | 1,244 |
|
Service cost | 257 |
| | 213 |
| 293 |
| | 262 |
|
Interest cost | 445 |
| | 435 |
| 455 |
| | 422 |
|
Benefits paid | (487 | ) | | (382 | ) | (596 | ) | | (466 | ) |
Actuarial loss (gain) | (582 | ) | | 1,780 |
| |
Plan amendments | | (26 | ) | | 39 |
|
Actuarial (gain) loss | | 1,297 |
| | 342 |
|
Balance at end of year | 10,542 |
| | 10,909 |
| 13,808 |
| | 12,385 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 9,690 |
| | 8,733 |
| 11,583 |
| | 9,234 |
|
Acquisitions | | — |
| | 837 |
|
Actual return (loss) on plan assets | (14 | ) | | 797 |
| 1,953 |
| | 902 |
|
Employer contributions | 45 |
| | 542 |
| 52 |
| | 1,076 |
|
Benefits paid | (487 | ) | | (382 | ) | (596 | ) | | (466 | ) |
Fair value of plan assets at end of year | 9,234 |
| | 9,690 |
| 12,992 |
| | 11,583 |
|
Accrued liability | $ | (1,308 | ) | | $ | (1,219 | ) | $ | (816 | ) | | $ | (802 | ) |
At December 31, 20152017, the projected benefit obligations for the qualified and non-qualified pension plans were $10.0$13.2 billion and $582$652 million, respectively. All pension plan assets are related to the qualified pension plan.plans.
Amounts presented in the following tables exclude regulatory assets of $334 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 3,273 |
| | $ | 3,207 |
|
Other current liabilities | (53 | ) | | (53 | ) |
Employee benefit obligations | (763 | ) | | (749 | ) |
Other regulatory liabilities, deferred | (118 | ) | | (87 | ) |
Accumulated OCI | 107 |
| | 100 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 2,998 |
| | $ | 3,073 |
|
Other current liabilities | (46 | ) | | (42 | ) |
Employee benefit obligations | (1,262 | ) | | (1,177 | ) |
Accumulated OCI | 125 |
| | 134 |
|
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 20152017 and 20142016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2016.2018.
| | | Prior Service Cost | | Net (Gain) Loss | Prior Service Cost | | Net (Gain) Loss |
| (in millions) | (in millions) |
Balance at December 31, 2015: | | | | |
Balance at December 31, 2017: | | | | |
Accumulated OCI | $ | 3 |
| | $ | 122 |
| $ | 3 |
| | $ | 104 |
|
Regulatory assets | 27 |
| | 2,971 |
| 14 |
| | 3,140 |
|
Total | $ | 30 |
| | $ | 3,093 |
| $ | 17 |
| | $ | 3,244 |
|
Balance at December 31, 2014: | | | | |
Balance at December 31, 2016: | | | | |
Accumulated OCI | $ | 4 |
| | $ | 130 |
| $ | 4 |
| | $ | 96 |
|
Regulatory assets | 51 |
| | 3,022 |
| 51 |
| | 3,069 |
|
Total | $ | 55 |
| | $ | 3,152 |
| $ | 55 |
| | $ | 3,165 |
|
Estimated amortization in net periodic pension cost in 2016: | | | | |
Estimated amortization in net periodic pension cost in 2018: | | | | |
Accumulated OCI | $ | 1 |
| | $ | 6 |
| $ | 1 |
| | $ | 9 |
|
Regulatory assets | 13 |
| | 145 |
| 4 |
| | 204 |
|
Total | $ | 14 |
| | $ | 151 |
| $ | 5 |
| | $ | 213 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 20152017 and 20142016 are presented in the following table:
| | | Accumulated OCI | | Regulatory Assets | Accumulated OCI | | Regulatory Assets |
| (in millions) | (in millions) |
Balance at December 31, 2013 | $ | 64 |
| | $ | 1,651 |
| |
Net gain | 75 |
| | 1,552 |
| |
Balance at December 31, 2015 | | $ | 125 |
| | $ | 2,998 |
|
Net (gain) loss | | (20 | ) | | 243 |
|
Change in prior service costs | — |
| | 1 |
| 2 |
| | 37 |
|
Reclassification adjustments: | | | | | | |
Amortization of prior service costs | (1 | ) | | (25 | ) | (1 | ) | | (13 | ) |
Amortization of net gain | (4 | ) | | (106 | ) | |
Amortization of net gain (loss) | | (6 | ) | | (145 | ) |
Total reclassification adjustments | (5 | ) | | (131 | ) | (7 | ) | | (158 | ) |
Total change | 70 |
| | 1,422 |
| (25 | ) | | 122 |
|
Balance at December 31, 2014 | $ | 134 |
| | $ | 3,073 |
| |
Net loss | 1 |
| | 155 |
| |
Balance at December 31, 2016 | | $ | 100 |
| | $ | 3,120 |
|
Net (gain) loss | | 15 |
| | 227 |
|
Change in prior service costs | | — |
| | (26 | ) |
Reclassification adjustments: | | | | | | |
Amortization of prior service costs | (1 | ) | | (24 | ) | (1 | ) | | (11 | ) |
Amortization of net gain | (9 | ) | | (206 | ) | |
Amortization of net gain (loss) | | (7 | ) | | (155 | ) |
Total reclassification adjustments | (10 | ) | | (230 | ) | (8 | ) | | (166 | ) |
Total change | (9 | ) | | (75 | ) | 7 |
| | 35 |
|
Balance at December 31, 2015 | $ | 125 |
| | $ | 2,998 |
| |
Balance at December 31, 2017 | | $ | 107 |
| | $ | 3,155 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Components of net periodic pension cost were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Service cost | $ | 257 |
| | $ | 213 |
| | $ | 232 |
| $ | 293 |
| | $ | 262 |
| | $ | 257 |
|
Interest cost | 445 |
| | 435 |
| | 389 |
| 455 |
| | 422 |
| | 445 |
|
Expected return on plan assets | (724 | ) | | (645 | ) | | (603 | ) | (897 | ) | | (782 | ) | | (724 | ) |
Recognized net loss | 215 |
| | 110 |
| | 200 |
| |
Recognized net (gain) loss | | 162 |
| | 150 |
| | 215 |
|
Net amortization | 25 |
| | 26 |
| | 27 |
| 12 |
| | 14 |
| | 25 |
|
Net periodic pension cost | $ | 218 |
| | $ | 139 |
| | $ | 245 |
| $ | 25 |
| | $ | 66 |
| | $ | 218 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 20152017, estimated benefit payments were as follows:
| | | Benefit Payments | Benefit Payments |
| (in millions) | (in millions) |
2016 | $ | 450 |
| |
2017 | 478 |
| |
2018 | 501 |
| $ | 634 |
|
2019 | 527 |
| 637 |
|
2020 | 554 |
| 663 |
|
2021 to 2025 | 3,141 |
| |
2021 | | 681 |
|
2022 | | 704 |
|
2023 to 2027 | | 3,836 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 1,986 |
| | $ | 1,682 |
| $ | 2,297 |
| | $ | 1,989 |
|
Acquisitions | | — |
| | 338 |
|
Service cost | 23 |
| | 21 |
| 24 |
| | 22 |
|
Interest cost | 78 |
| | 79 |
| 79 |
| | 76 |
|
Benefits paid | (102 | ) | | (102 | ) | (136 | ) | | (119 | ) |
Actuarial loss (gain) | (38 | ) | | 300 |
| |
Actuarial (gain) loss | | 65 |
| | (16 | ) |
Plan amendments | 34 |
| | (2 | ) | 3 |
| | — |
|
Retiree drug subsidy | 8 |
| | 8 |
| 7 |
| | 7 |
|
Balance at end of year | 1,989 |
| | 1,986 |
| 2,339 |
| | 2,297 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 900 |
| | 901 |
| 944 |
| | 833 |
|
Acquisitions | | — |
| | 100 |
|
Actual return (loss) on plan assets | (12 | ) | | 54 |
| 154 |
| | 58 |
|
Employer contributions | 39 |
| | 39 |
| 84 |
| | 65 |
|
Benefits paid | (94 | ) | | (94 | ) | (129 | ) | | (112 | ) |
Fair value of plan assets at end of year | 833 |
| | 900 |
| 1,053 |
| | 944 |
|
Accrued liability | $ | (1,156 | ) | | $ | (1,086 | ) | $ | (1,286 | ) | | $ | (1,353 | ) |
Amounts presented in the following tables exclude regulatory assets of $77 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 20152017 and 20142016 related to the Company's other postretirement benefit plans consist of the following:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Other regulatory assets, deferred | $ | 433 |
| | $ | 387 |
| $ | 382 |
| | $ | 419 |
|
Other current liabilities | (4 | ) | | (4 | ) | (5 | ) | | (4 | ) |
Employee benefit obligations | (1,152 | ) | | (1,082 | ) | (1,281 | ) | | (1,349 | ) |
Other regulatory liabilities, deferred | (22 | ) | | (21 | ) | (41 | ) | | (41 | ) |
Accumulated OCI | 8 |
| | 8 |
| 4 |
| | 7 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 20152017 and 20142016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2016.2018.
| | | Prior Service Cost | | Net (Gain) Loss | Prior Service Cost | | Net (Gain) Loss |
| (in millions) | (in millions) |
Balance at December 31, 2015: | | | | |
Balance at December 31, 2017: | | | | |
Accumulated OCI | $ | — |
| | $ | 8 |
| $ | — |
| | $ | 4 |
|
Net regulatory assets | 32 |
| | 379 |
| 21 |
| | 320 |
|
Total | $ | 32 |
| | $ | 387 |
| $ | 21 |
| | $ | 324 |
|
Balance at December 31, 2014: | | | | |
Balance at December 31, 2016: | | | | |
Accumulated OCI | $ | — |
| | $ | 8 |
| $ | — |
| | $ | 7 |
|
Net regulatory assets | 2 |
| | 364 |
| 25 |
| | 353 |
|
Total | $ | 2 |
| | $ | 372 |
| $ | 25 |
| | $ | 360 |
|
Estimated amortization as net periodic postretirement benefit cost in 2016: | | | | |
Estimated amortization as net periodic postretirement benefit cost in 2018: | | | | |
Net regulatory assets | $ | 6 |
| | $ | 14 |
| $ | 7 |
| | $ | 14 |
|
The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 20152017 and 20142016 are presented in the following table:
| | | Accumulated OCI | | Net Regulatory Assets (Liabilities) | Accumulated OCI | | Net Regulatory Assets (Liabilities) |
| (in millions) | (in millions) |
Balance at December 31, 2013 | $ | 1 |
| | $ | 73 |
| |
Net gain | 7 |
| | 301 |
| |
Balance at December 31, 2015 | | $ | 8 |
| | $ | 411 |
|
Net (gain) loss | | (1 | ) | | (13 | ) |
Reclassification adjustments: | | | | |
Amortization of prior service costs | | — |
| | (6 | ) |
Amortization of net gain (loss) | | — |
| | (14 | ) |
Total reclassification adjustments | | — |
| | (20 | ) |
Total change | | (1 | ) | | (33 | ) |
Balance at December 31, 2016 | | $ | 7 |
| | $ | 378 |
|
Net (gain) loss | | (3 | ) | | (21 | ) |
Change in prior service costs | — |
| | (2 | ) | — |
| | 3 |
|
Reclassification adjustments: | | | | | | |
Amortization of prior service costs | — |
| | (4 | ) | — |
| | (6 | ) |
Amortization of net gain | — |
| | (2 | ) | |
Amortization of net gain (loss) | | — |
| | (13 | ) |
Total reclassification adjustments | — |
| | (6 | ) | — |
| | (19 | ) |
Total change | 7 |
| | 293 |
| (3 | ) | | (37 | ) |
Balance at December 31, 2014 | $ | 8 |
| | $ | 366 |
| |
Net gain | — |
| | 33 |
| |
Change in prior service costs | — |
| | 33 |
| |
Reclassification adjustments: | | | | |
Amortization of prior service costs | — |
| | (4 | ) | |
Amortization of net gain | — |
| | (17 | ) | |
Total reclassification adjustments | — |
| | (21 | ) | |
Total change | — |
| | 45 |
| |
Balance at December 31, 2015 | $ | 8 |
| | $ | 411 |
| |
Balance at December 31, 2017 | | $ | 4 |
| | $ | 341 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Components of the other postretirement benefit plans' net periodic cost were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Service cost | $ | 23 |
| | $ | 21 |
| | $ | 24 |
| $ | 24 |
| | $ | 22 |
| | $ | 23 |
|
Interest cost | 78 |
| | 79 |
| | 74 |
| 79 |
| | 76 |
| | 78 |
|
Expected return on plan assets | (58 | ) | | (59 | ) | | (56 | ) | (66 | ) | | (60 | ) | | (58 | ) |
Net amortization | 21 |
| | 6 |
| | 21 |
| 20 |
| | 21 |
| | 21 |
|
Net periodic postretirement benefit cost | $ | 64 |
| | $ | 47 |
| | $ | 63 |
| $ | 57 |
| | $ | 59 |
| | $ | 64 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
| | | Benefit Payments | | Subsidy Receipts | | Total | Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) | (in millions) |
2016 | $ | 123 |
| | $ | (9 | ) | | $ | 114 |
| |
2017 | 128 |
| | (10 | ) | | 118 |
| |
2018 | 133 |
| | (11 | ) | | 122 |
| $ | 144 |
| | $ | (7 | ) | | $ | 137 |
|
2019 | 137 |
| | (12 | ) | | 125 |
| 148 |
| | (8 | ) | | 140 |
|
2020 | 139 |
| | (12 | ) | | 127 |
| 151 |
| | (8 | ) | | 143 |
|
2021 to 2025 | 711 |
| | (65 | ) | | 646 |
| |
2021 | | 154 |
| | (9 | ) | | 145 |
|
2022 | | 156 |
| | (9 | ) | | 147 |
|
2023 to 2027 | | 780 |
| | (48 | ) | | 732 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension planplans and the other postretirement benefit plans cover a diversified mix of assets including equity and fixed income securities, real estate, and private equity.as described below. Derivative instruments aremay be used primarily to gain efficient exposure to the various asset classes and as hedging tools. TheAdditionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2015 and 2014, along with the targeted mix of assets for each plan, is presented below:
|
| | | | | | | | |
| Target | | 2015 | | 2014 |
Pension plan assets: | | | | | |
Domestic equity | 26 | % | | 30 | % | | 30 | % |
International equity | 25 |
| | 23 |
| | 23 |
|
Fixed income | 23 |
| | 23 |
| | 27 |
|
Special situations | 3 |
| | 2 |
| | 1 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
|
Private equity | 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | |
Domestic equity | 42 | % | | 38 | % | | 41 | % |
International equity | 21 |
| | 23 |
| | 23 |
|
Domestic fixed income | 24 |
| | 26 |
| | 26 |
|
Global fixed income | 4 |
| | 4 |
| | 3 |
|
Special situations | 1 |
| | 1 |
| | — |
|
Real estate investments | 5 |
| | 6 |
| | 5 |
|
Private equity | 3 |
| | 2 |
| | 2 |
|
Total | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension planplans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension planplans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.
Investment Strategies
Detailed below Management believes the portfolio is a descriptionwell-diversified with no significant concentrations of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:risk.
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Investment Strategies and Benefit Plan Asset Fair Values
Following areA description of the fair value measurements formajor asset classes that the pension plan and the other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:
|
| |
Description | Valuation Methodology |
● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. |
● Fixed income: A mix of domestic and international bonds. | Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. |
● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. |
● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature.
● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. |
The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan assets(excluding Southern Company Gas) as of December 31, 20152017 and 2014.2016 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
Real estate investments and private equity.Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
TheThese fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income and pending investmentsinvestment sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | Target Allocation | Actual Allocation |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | |
Domestic equity* | $ | 1,632 |
| | $ | 681 |
| | $ | — |
| | $ | — |
| | $ | 2,313 |
| |
International equity* | 1,190 |
| | 990 |
| | — |
| | — |
| | 2,180 |
| |
Domestic equity(*) | | $ | 2,405 |
| $ | 1,159 |
| $ | — |
| $ | — |
| $ | 3,564 |
| 26 | % | 31 | % |
International equity(*) | | 1,555 |
| 1,403 |
| — |
| — |
| 2,958 |
| 25 |
| 25 |
|
Fixed income: | | | | | | | | | | | 23 |
| 24 |
|
U.S. Treasury, government, and agency bonds | — |
| | 454 |
| | — |
| | — |
| | 454 |
| — |
| 841 |
| — |
| — |
| 841 |
|
|
Mortgage- and asset-backed securities | — |
| | 199 |
| | — |
| | — |
| | 199 |
| — |
| 8 |
| — |
| — |
| 8 |
|
|
Corporate bonds | — |
| | 1,140 |
| | — |
| | — |
| | 1,140 |
| — |
| 1,201 |
| — |
| — |
| 1,201 |
|
|
Pooled funds | — |
| | 500 |
| | — |
| | — |
| | 500 |
| — |
| 650 |
| — |
| — |
| 650 |
|
|
Cash equivalents and other | — |
| | 145 |
| | — |
| | — |
| | 145 |
| 217 |
| 11 |
| — |
| — |
| 228 |
|
|
Real estate investments | 299 |
| | — |
| | — |
| | 1,218 |
| | 1,517 |
| 469 |
| — |
| — |
| 1,188 |
| 1,657 |
| 14 |
| 13 |
|
Special situations | | — |
| — |
| — |
| 180 |
| 180 |
| 3 |
| 1 |
|
Private equity | — |
| | — |
| | — |
| | 635 |
| | 635 |
| — |
| — |
| — |
| 669 |
| 669 |
| 9 |
| 6 |
|
Total | $ | 3,121 |
| | $ | 4,109 |
| | $ | — |
| | $ | 1,853 |
| | $ | 9,083 |
| $ | 4,646 |
| $ | 5,273 |
| $ | — |
| $ | 2,037 |
| $ | 11,956 |
| 100 | % | 100 | % |
Liabilities: | | | | | | | | | | |
Derivatives | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) | |
Total | $ | 3,120 |
| | $ | 4,109 |
| | $ | — |
| | $ | 1,853 |
| | $ | 9,082 |
| |
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 1,704 |
| | $ | 704 |
| | $ | — |
| | $ | — |
| | $ | 2,408 |
|
International equity* | 1,070 |
| | 986 |
| | — |
| | — |
| | 2,056 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 699 |
| | — |
| | — |
| | 699 |
|
Mortgage- and asset-backed securities | — |
| | 188 |
| | — |
| | — |
| | 188 |
|
Corporate bonds | — |
| | 1,135 |
| | — |
| | — |
| | 1,135 |
|
Pooled funds | — |
| | 514 |
| | — |
| | — |
| | 514 |
|
Cash equivalents and other | 3 |
| | 660 |
| | — |
| | — |
| | 663 |
|
Real estate investments | 293 |
| | — |
| | — |
| | 1,121 |
| | 1,414 |
|
Private equity | — |
| | — |
| | — |
| | 570 |
| | 570 |
|
Total | $ | 3,070 |
| | $ | 4,886 |
| | $ | — |
| | $ | 1,691 |
| | $ | 9,647 |
|
Liabilities: | | | | | | | | | |
Derivatives | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (2 | ) |
Total | $ | 3,068 |
| | $ | 4,886 |
| | $ | — |
| | $ | 1,691 |
| | $ | 9,645 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 2,010 |
| $ | 927 |
| $ | — |
| $ | — |
| $ | 2,937 |
| 26 | % | 29 | % |
International equity(*) | 1,231 |
| 1,110 |
| — |
| — |
| 2,341 |
| 25 |
| 22 |
|
Fixed income: | | | | | | 23 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 588 |
| — |
| — |
| 588 |
|
|
|
Mortgage- and asset-backed securities | — |
| 13 |
| — |
| — |
| 13 |
|
|
|
Corporate bonds | — |
| 991 |
| — |
| — |
| 991 |
|
|
|
Pooled funds | — |
| 524 |
| — |
| — |
| 524 |
|
|
|
Cash equivalents and other | 996 |
| 2 |
| — |
| — |
| 998 |
|
|
|
Real estate investments | 310 |
| — |
| — |
| 1,152 |
| 1,462 |
| 14 |
| 13 |
|
Special situations | — |
| — |
|
|
| 180 |
| 180 |
| 3 |
| 2 |
|
Private equity | — |
| — |
| — |
| 549 |
| 549 |
| 9 |
| 5 |
|
Total | $ | 4,547 |
| $ | 4,155 |
| $ | — |
| $ | 1,881 |
| $ | 10,583 |
| 100 | % | 100 | % |
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations |
The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 155 |
| $ | 323 |
| $ | — |
| $ | — |
| $ | 478 |
|
International equity(*) | — |
| 166 |
| — |
| — |
| 166 |
|
Fixed income: | | | | | |
U.S. Treasury, government, and agency bonds | — |
| 85 |
| — |
| — |
| 85 |
|
Corporate bonds | — |
| 39 |
| — |
| — |
| 39 |
|
Cash equivalents and other | 84 |
| 25 |
| — |
| 48 |
| 157 |
|
Real estate investments | 3 |
| — |
| — |
| 16 |
| 19 |
|
Private equity | — |
| — |
| — |
| 1 |
| 1 |
|
Total | $ | 242 |
| $ | 638 |
| $ | — |
| $ | 65 |
| $ | 945 |
|
| |
(*) | Level 1 securities consist of risk.actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | Total | Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | | |
As of December 31, 2016: | | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | |
Domestic equity* | $ | 106 |
| | $ | 52 |
| | $ | — |
| | $ | — |
| | $ | 158 |
| |
International equity* | 40 |
| | 64 |
| | — |
| | — |
| | 104 |
| |
Domestic equity(*) | | $ | 142 |
| $ | 343 |
| $ | — |
| $ | — |
| $ | 485 |
|
International equity(*) | | — |
| 185 |
| — |
| — |
| 185 |
|
Fixed income: | | | | | | | | | |
|
U.S. Treasury, government, and agency bonds | — |
| | 22 |
| | — |
| | — |
| | 22 |
| — |
| 85 |
| — |
| — |
| 85 |
|
Mortgage- and asset-backed securities | — |
| | 7 |
| | — |
| | — |
| | 7 |
| |
Corporate bonds | — |
| | 38 |
| | — |
| | — |
| | 38 |
| — |
| 41 |
| — |
| — |
| 41 |
|
Pooled funds | — |
| | 42 |
| | — |
| | — |
| | 42 |
| — |
| 66 |
| — |
| — |
| 66 |
|
Cash equivalents and other | 11 |
| | 9 |
| | — |
| | — |
| | 20 |
| 12 |
| 5 |
| — |
| 83 |
| 100 |
|
Trust-owned life insurance | — |
| | 370 |
| | — |
| | — |
| | 370 |
| |
Real estate investments | 11 |
| | — |
| | — |
| | 41 |
| | 52 |
| 4 |
| — |
| — |
| 15 |
| 19 |
|
Private equity | — |
| | — |
| | — |
| | 21 |
| | 21 |
| — |
| — |
| — |
| 2 |
| 2 |
|
Total | $ | 168 |
| | $ | 604 |
| | $ | — |
| | $ | 62 |
| | $ | 834 |
| $ | 158 |
| $ | 725 |
| $ | — |
| $ | 100 |
| $ | 983 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | |
Equity | | 53 | % | | 65 | % | | 69 | % |
Fixed Income | | 15 |
| | 19 |
| | 20 |
|
Cash | | 2 |
| | 6 |
| | 1 |
|
Other | | 30 |
| | 10 |
| | 10 |
|
Balance at end of period | | 100 | % | | 100 | % | | 100 | % |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 147 |
| | $ | 56 |
| | $ | — |
| | $ | — |
| | $ | 203 |
|
International equity* | 36 |
| | 67 |
| | — |
| | — |
| | 103 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Mortgage- and asset-backed securities | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Corporate bonds | — |
| | 39 |
| | — |
| | — |
| | 39 |
|
Pooled funds | — |
| | 41 |
| | — |
| | — |
| | 41 |
|
Cash equivalents and other | 9 |
| | 27 |
| | — |
| | — |
| | 36 |
|
Trust-owned life insurance | — |
| | 381 |
| | — |
| | — |
| | 381 |
|
Real estate investments | 11 |
| | — |
| | — |
| | 37 |
| | 48 |
|
Private equity | — |
| | — |
| | — |
| | 19 |
| | 19 |
|
Total | $ | 203 |
| | $ | 646 |
| | $ | — |
| | $ | 56 |
| | $ | 905 |
|
The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 132 |
| $ | 35 |
| $ | — |
| $ | — |
| $ | 167 |
| 37 | % | 40 | % |
International equity(*) | 47 |
| 76 |
| — |
| — |
| 123 |
| 23 |
| 23 |
|
Fixed income: | | | | | | 30 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 32 |
| — |
| — |
| 32 |
|
|
|
Corporate bonds | — |
| 37 |
| — |
| — |
| 37 |
|
|
|
Pooled funds | — |
| 55 |
| — |
| — |
| 55 |
|
|
|
Cash equivalents and other | 10 |
| — |
| — |
| — |
| 10 |
|
|
|
Trust-owned life insurance | — |
| 426 |
| — |
| — |
| 426 |
|
|
|
Real estate investments | 16 |
| — |
| — |
| 36 |
| 52 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 20 |
| 20 |
| 4 |
| 2 |
|
Total | $ | 205 |
| $ | 661 |
| $ | — |
| $ | 61 |
| $ | 927 |
| 100 | % | 100 | % |
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 118 |
| $ | 28 |
| $ | — |
| $ | — |
| $ | 146 |
| 39 | % | 40 | % |
International equity(*) | 37 |
| 61 |
| — |
| — |
| 98 |
| 23 |
| 21 |
|
Fixed income: | | | | | | 29 |
| 31 |
|
U.S. Treasury, government, and agency bonds | — |
| 24 |
| — |
| — |
| 24 |
|
|
|
Corporate bonds | — |
| 30 |
| — |
| — |
| 30 |
|
|
|
Pooled funds | — |
| 49 |
| — |
| — |
| 49 |
|
|
|
Cash equivalents and other | 41 |
| — |
| — |
| — |
| 41 |
|
|
|
Trust-owned life insurance | — |
| 382 |
| — |
| — |
| 382 |
|
|
|
Real estate investments | 11 |
| — |
| — |
| 35 |
| 46 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 17 |
| 17 |
| 3 |
| 2 |
|
Total | $ | 207 |
| $ | 574 |
| $ | — |
| $ | 57 |
| $ | 838 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of risk.actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 69 |
| $ | — |
| $ | — |
| $ | 72 |
|
International equity(*) | — |
| 22 |
| — |
| — |
| 22 |
|
Fixed income: | | | | |
|
|
Pooled funds | — |
| 24 |
| — |
| — |
| 24 |
|
Cash equivalents and other | 2 |
| — |
| — |
| 1 |
| 3 |
|
Total | $ | 5 |
| $ | 115 |
| $ | — |
| $ | 1 |
| $ | 121 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 58 |
| $ | — |
| $ | — |
| $ | 61 |
|
International equity(*) | — |
| 18 |
| — |
| — |
| 18 |
|
Fixed income: | | | | | |
Pooled funds | — |
| 23 |
| — |
| — |
| 23 |
|
Cash equivalents and other | 1 |
| — |
| — |
| 2 |
| 3 |
|
Total | $ | 4 |
| $ | 99 |
| $ | — |
| $ | 2 |
| $ | 105 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Other postretirement benefit plan assets: | | | | | | |
Equity | | 72 | % | | 76 | % | | 74 | % |
Fixed Income | | 24 |
| | 20 |
| | 23 |
|
Cash | | 1 |
| | 2 |
| | 1 |
|
Other | | 3 |
| | 2 |
| | 2 |
|
Total | | 100 | % | | 100 | % | | 100 | % |
Employee Savings Plan
Southern Company and its subsidiaries also sponsors asponsor 401(k) defined contribution planplans covering substantially all employees. The Company provides an 85%employees and provide matching contribution oncontributions up to 6%specified percentages of an employee's base salary.eligible pay. Total matching contributions made to the planplans for 20152017, 20142016, and 20132015 were $92$118 million, $87105 million, and $8492 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.
AGL Resources Merger Litigation
AGL Resources and each member of the AGL Resources board of directors were named as defendants in four purported shareholder class action lawsuits filed in the United States District Court for the Northern District of Georgia in September and October 2015. These actions were filed on behalf of named plaintiffs and other AGL Resources shareholders challenging the Merger and seeking, among other things, preliminary and permanent injunctive relief enjoining the Merger, and, in certain circumstances, damages. Southern Company and Merger Sub were also named as defendants in two of these lawsuits. On October 23, 2015, the court consolidated the four lawsuits into a single action. On January 4, 2016, the parties filed a proposed stipulated
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
order of dismissal, asking the court to dismiss the consolidated amended complaint without prejudice, which the court approved on January 5, 2016. See Note 12 under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have eachrecognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These ratesregulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs.PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability as of December 31, 20152017 and 2016 was $29 million.$22 million and $17 million, respectively. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of othersuch sites are anticipated.is expected.
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's financial statements.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46$52 million and $44 million as of December 31, 2015.2017 and 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf PowerPower's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.
The finalultimate outcome of these matters cannot be determined at this time. However, basedtime; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to theSouthern Company's financial statements.statements.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19,In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. In March 2015, Georgia Powerwhich was credited the award to accounts where the original costs were charged, and reducedused to reduce rate base, fuel, and cost of service for the benefit of customers. In NovemberAlso in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the retail-related proceeds to offsetcost of service for the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, Alabama Power credited the wholesale-related proceeds to each wholesale customer.benefit of customers.
In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
December 31, 20152017 for any potential recoveries from the additionalpending lawsuits. The final outcome of these matters cannot be determined at this time; however,time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, no material impact on Southern Company's net income is expected.
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Regulatory Matters
Alabama Power
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21%. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
In 2013, the Alabama PSC approved a revision to Rate RSE, effective for calendar year 2014. This revision established the WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
The Rate RSE increaseadjustments for 2015any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was 3.49% or $181 million annually, and was effective Januarywithin the allowed WCE range. On December 1, 2015. On November 30, 2015,2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016.2018. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.2018.
In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service under Rate CNP.service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015,7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 20152017 through March 31, 2016.2018. No adjustment to Rate CNP PPA is expected in 2016.2018. As of December 31, 2015,2017 and 2016, Alabama Power had an under recovered certificatedRate CNP PPA balance of $99$12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP Environmental allowedPPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Rate CNP Compliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated
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annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.
Revenues for Rate CNP Compliance, increased 1.5%,as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or $75net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million annually,of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2015.2017.
On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2015,2017 and 2016, Alabama Power had an under recovered compliance clause balance of $43 million, which is included ina deferred under recovered regulatory clause revenues in the balance sheet.of $17 million and $9 million, respectively.
Integrated Resource Plan
See "Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of CCR and CO2.
In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory
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Southern Company and Subsidiary Companies 2017 Annual Report
asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.
Gulf Power
On April 4, 2017, the Florida PSC approved the 2017 Rate ECRCase Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
AlabamaThe 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power has established energymust identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates under Alabamaeffective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's Rate ECR as approvedfuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the Alabama PSC. Rates areparties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an estimateincreased equity ratio of future energy55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its
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Southern Company and Subsidiary Companies 2017 Annual Report
distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the current overbilling factor will not have a significant effect on revenues or under recovered balance. Revenues recognized under Rate ECRnet income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and recorded onenergy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under these programs for 2018 is $395 million.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for the differencedifferences in actual recoverable fuel costs and amounts billed in current regulated rates. The differenceAccordingly, changes in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor will not have noa significant effect on Southern Company's revenues or net income, but will impactaffect cash flow. The traditional electric operating cash flows. Currently, the Alabama PSC may approve billing ratescompanies continuously monitor their under Rate ECR of upor over recovered fuel cost balances and make appropriate filings with their state PSCs to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the Rate ECR factor of 2.681 cents per KWH.
On December 1, 2015, the Alabama PSC approved a decrease in Alabama Power’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on Southern Company's net income, but will decrease operating cash flows related toadjust fuel cost recovery rates as necessary.
See Note 1 to the financial statements under "Revenues" and Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" for additional information.
Kemper County Energy Facility
The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in 2016 when comparedthe 2010 CPCN proceedings, subject to 2015.a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural
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Southern Company and Subsidiary Companies 2017 Annual Report
gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The Kemper Settlement Order established the Kemper Settlement Docket for the purposes of pursuing a global settlement of the related costs.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will return to 2.681 cents per KWH in 2017reflect a reduction of approximately $26.8 million annually and 5.910 cents per KWHinclude no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 absentor at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a further order fromreserve margin plan with the Alabama PSC.Mississippi PSC by August 2018.
Alabama Power's over recovered fuelDuring the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2015 totaled $238 million as compared to $47 million at2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2014. At December 31, 2015, $238 million2017.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is includedresolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other regulatory liabilities, current.things, Southern Company as a defendant. The over recovered fuel costs at December 31, 2014 are included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability,individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy demand,facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the price of energy. A changeCircuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of these factorsmotions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the
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plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop and other related parties and the arbitration was dismissed.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. The Southern Company system's construction program is currently estimated to total approximately $9.4 billion, $9.3 billion, $8.4 billion, $7.0 billion, and $6.9 billion for 2018, 2019, 2020, 2021, and 2022, respectively.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements under "Nuclear Construction" for additional information. See Note 12 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities. See Note 3 to the financial statements under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Nuclear Construction
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor
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Southern Company and Subsidiary Companies 2017 Annual Report
and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
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Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.
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Southern Company and Subsidiary Companies 2017 Annual Report
In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down by 20% each year until completely phased out for qualified property placed in service after December 31, 2027. Further, the business interest deduction is limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforwards, and depreciation and amortization through December 31, 2021, and thereafter to 30% of taxable income excluding interest and NOL carryforwards.
Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of the consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $264 million, a $0.4 billion decrease in regulatory assets, and a $6.9 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities. Also, the OCI ending balance at December 31, 2017 includes $30 million of stranded excess deferred tax balances, which will be adjusted through retained earnings in subsequent periods.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. On January 31, 2018, SCS, on behalf of the traditional electric operating companies, filed with the FERC a reduction to the open access transmission tariff charge for 2018 to reflect the revised federal corporate income tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the traditional electric operating companies' and the natural gas distribution utilities' rate filings to reflect the impacts of the Tax Reform Legislation.
On February 9, 2018, the Bipartisan Budget Act of 2018 was signed into law. Included in the tax extenders portion of the law were provisions extending PTCs on advanced nuclear power facilities and ITCs on qualified fuel cells. A subsidiary of PowerSecure installed fuel cells in 2017 which are expected to qualify for approximately $80 million of ITCs; however, the impact of the related tax benefits would be substantially offset by additional required payments under the applicable purchase contracts. Should Southern Company have a NOL in 2018, all of these ITCs may not be fully realized in 2018. See Note 3 to the financial statements under "Nuclear Construction" for additional information on the PTCs relating to advanced nuclear power facilities.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $870 million for the 2017 tax year and approximately $290 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes – Net Operating Loss," respectively, for additional information. The ultimate outcome of these matters cannot be determined at this time.
Tax Credits
The Tax Reform Legislation retained the renewable energy incentives that were included in the PATH Act. The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits and the tax benefit related to basis differences.
Southern Power
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. Southern Power is pursuing the sale of a 33% equity interest in the newly-formed holding company owning these solar assets. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In 2016, the SEC began conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with no recommended enforcement action.
Litigation
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Investments in Leveraged Leases
A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any recovery or returnfuture) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of fuel costs.the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate NDRBased on
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Alabama PSC, Alabama Power maintainsLouisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a reserve forsignificant impact on Southern Company's financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and maintenancerelated disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 86% of Southern Company's total operating revenues for 2017, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to coverthe financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper County Energy Facility Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. Mississippi Power recorded total pre-tax charges to income related
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge of $78 million associated with the Kemper Settlement Agreement.
In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 14 to the financial statements for additional information on the individual charges by quarter.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and no longer represents a critical accounting estimate.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on Southern Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, Southern Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of damages from major stormsfuture removal activities.
The liability for AROs primarily relates to itsfacilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities. facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
The order approvescost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
Southern Company's calculation of pension and other postretirement benefits expense is dependent on a separate monthly Rate NDRnumber of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, Southern Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
component of net periodic pension and other postretirement benefit plan expense decreased by approximately $96 million in 2016.
The following table illustrates the sensitivity to changes in Southern Company's long-term assumptions with respect to the assumed discount rate, the assumed salaries, and the assumed long-term rate of return on plan assets:
|
| | | | | |
Change in Assumption | Increase/(Decrease) in Total Benefit Expense for 2018 | | Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2017 | | Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2017 |
| (in millions) |
25 basis point change in discount rate | $40/$(38) | | $504/$(476) | | $68/$(65) |
25 basis point change in salaries | $24/$(23) | | $119/$(115) | | $–/$– |
25 basis point change in long-term return on plan assets | $33/$(33) | | N/A | | N/A |
N/A – Not applicable
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Goodwill and Other Intangible Assets
The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.3 billion at December 31, 2017.
Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power's acquisitions, other intangible assets, net of amortization totaled approximately $873 million at December 31, 2017.
The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.
See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding Southern Company's goodwill and other intangible assets and Note 12 to the financial statements for additional information related to Southern Company's recent acquisitions and proposed dispositions.
Derivatives and Hedging Activities
Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.
Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:
the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the impact of Southern Company's nonperformance risk on its liabilities.
Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.
Contingent Obligations
Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers consistingat the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of two components. revenue and the related cash flows arising from contracts with customers.
Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.
Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The firstnew standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is intended to establisheligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and maintain a reserve balance for future stormsthe other components of net periodic pension and is an on-going partpostretirement benefit costs in the income statement. The capitalization of customer billing. The secondonly the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the Rate NDR chargeFASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is intendedeffective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
FINANCIAL CONDITION AND LIQUIDITY
Overview
Earnings in all periods presented were negatively affected by charges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, 2017.
The Southern Company system's cash requirements primarily consist of anyfunding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing deferred storm-related operationselectric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and maintenance costsimprove electric transmission and any future reserve deficits overdistribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate asubstantial portion of the NDRSouthern Company system's cash needs. For the three-year period from 2018 through 2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to reliability-relatedexceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Southern Company's investments in the qualified pension plans and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plans are anticipated during 2018. See "Contractual Obligations" herein and Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities in 2017 totaled $6.4 billion, an increase of $1.5 billion from 2016. The increase in net cash provided from operating activities was primarily due to increases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in 2016, partially offset by the timing of vendor payments. Net cash provided from operating activities in 2016 totaled $4.9 billion, a decrease of $1.4 billion from 2015. Significant changes in operating cash flow for 2016 as compared to 2015 included approximately $1.0 billion of voluntary contributions to the qualified pension plan in 2016 and a $1.2 billion increase in unutilized ITCs and PTCs.
Net cash used for investing activities in 2017, 2016, and 2015 totaled $7.2 billion, $20.0 billion, and $7.3 billion, respectively. The cash used for investing activities in 2017 was primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 was primarily due to the traditional electric operating companies' gross property additions for installation of equipment at electric generating facilities to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Power's acquisitions of solar facilities, and purchases of nuclear fuel.
Net cash provided from financing activities totaled $1.0 billion in 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries' continuous construction programs, Southern Power's acquisitions, and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Net cash provided from financing activities totaled $1.7 billion in 2015 primarily due to issuances of long-term debt and common stock and an increase in short-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes in 2017 included decreases of $7.3 billion and $0.8 billion in accumulated deferred income taxes and deferred charges related to income taxes, respectively, and an increase of $7.0 billion in deferred credits related to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
income taxes primarily resulting from the impacts of the Tax Reform Legislation; an increase of $1.4 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.8 billion write-down of the gasification portions of the Kemper County energy facility and payments of $1.7 billion received by Georgia Power under the Guarantee Settlement Agreement; an increase of $3.1 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $1.1 billion in total stockholder's equity primarily related to the Kemper County energy facility charges, partially offset by the issuance of additional shares of common stock. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" and "Financing Activities" herein and Note 3 to the financial statements under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.
At the end of 2017, the market price of Southern Company's common stock was $48.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book value ratio of 201%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016.
Southern Company's consolidated ratio of common equity to total capitalization plus short-term debt was 31.5% and 33.3% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of the Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from any potential sale of a 33% equity interest in a newly-formed holding company that owns substantially all of its solar assets, if completed. Southern Company Gas also plans to utilize the proceeds from the pending asset sales of two of its natural gas distribution utilities. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of December 31, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system.
In addition, Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
As of December 31, 2017, Southern Company's current liabilities exceeded current assets by $3.5 billion, due to $3.9 billion of long-term debt that is due within one year (comprised of approximately $1.0 billion at the parent company, $0.9 billion at Georgia Power, $1.0 billion at Mississippi Power, $0.8 billion at Southern Power, and $0.2 billion at Southern Company Gas) and $2.4 billion of notes payable (comprised of approximately $0.6 billion at the parent company, $0.2 billion at Georgia Power, $0.1 billion at Southern Power, and $1.5 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At December 31, 2017, Southern Company and its subsidiaries had approximately $2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2018 |
| 2019 |
| 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
Southern Company(a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Southern Company Consolidated | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.
At December 31, 2017, Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, had $200 million of gas facility revenue bonds outstanding. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. See FUTURE EARNINGS POTENTIAL – "General" herein and Note 6 to the financial statements under "Gas Facility Revenue Bonds" for additional information.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017: | | | | | | | | | |
Commercial paper | $ | 1,832 |
| | 1.8 | % | | $ | 2,117 |
| | 1.3 | % | | $ | 2,946 |
|
Short-term bank debt | 607 |
| | 2.3 | % | | 555 |
| | 2.1 | % | | 1,020 |
|
Total | $ | 2,439 |
| | 1.9 | % | | $ | 2,672 |
| | 1.5 | % | | |
December 31, 2016: | | | | | | | | | |
Commercial paper | $ | 1,909 |
| | 1.1 | % | | $ | 976 |
| | 0.8 | % | | $ | 1,970 |
|
Short-term bank debt | 123 |
| | 1.7 | % | | 176 |
| | 1.7 | % | | 500 |
|
Total | $ | 2,032 |
| | 1.1 | % | | $ | 1,152 |
| | 1.1 | % | | |
December 31, 2015: | | | | | | | | | |
Commercial paper | $ | 740 |
| | 0.7 | % | | $ | 842 |
| | 0.4 | % | | $ | 1,563 |
|
Short-term bank debt | 500 |
| | 1.4 | % | | 444 |
| | 1.1 | % | | 795 |
|
Total | $ | 1,240 |
| | 0.9 | % | | $ | 1,286 |
| | 0.5 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015. |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.
Furthermore, in connection with the acquisition of a solar facility in July 2016, a subsidiary of Southern Power Company assumed a $217 million construction loan, which was fully repaid in September 2016. During this period, the credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.2%.
The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Financing Activities
During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 950 |
| | $ | 400 |
|
Alabama Power | 1,100 |
| | 525 |
| | — |
| | 36 |
| | — |
| | — |
|
Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 65 |
| | 370 |
| | 17 |
|
Gulf Power | 300 |
| | 85 |
| | — |
| | — |
| | 6 |
| | — |
|
Mississippi Power | — |
| | 35 |
| | — |
| | — |
| | 40 |
| | 962 |
|
Southern Power | 525 |
| | 500 |
| | — |
| | — |
| | 43 |
| | 18 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | — |
| | 400 |
| | 22 |
|
Other | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
Elimination(d) | — |
| | — |
| | — |
| | — |
| | (40 | ) | | (602 | ) |
Southern Company Consolidated | $ | 4,025 |
| | $ | 1,995 |
| | $ | 65 |
| | $ | 101 |
| | $ | 1,769 |
| | $ | 832 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas. |
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The majority of the proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock.
In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
At December 31, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a partresult of an annual budget processa credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 40 |
|
At BBB- and/or Baa3 | $ | 665 |
|
At BB+ and/or Ba1(*) | $ | 2,390 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets and would be likely to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
impact the cost at which they do so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch Ratings, Inc. placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
On January 19, 2018, Moody's revised its rating outlooks for Southern Company and Alabama Power from stable to negative.
While it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Absent actions by Southern Company and its subsidiaries to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation.
Market Price Risk
The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the followingremaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 2017 have a notional amount of $3.7 billion and are intended to mitigate interest rate volatility related to existing fixed and floating rate obligations. The weighted average interest rate on $6.3 billion of long-term variable interest rate exposure at December 31, 2017 was 2.43%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $63 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies. Southern Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | 41 |
| | $ | (213 | ) |
Acquisitions | — |
| | (54 | ) |
Contracts realized or settled | (8 | ) | | 141 |
|
Current period changes(a) | (196 | ) | | 171 |
|
Contracts outstanding at the end of the period, assets (liabilities), net(b) | $ | (163 | ) | | $ | 45 |
|
| |
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
| |
(b) | Excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016. |
The net hedge volumes of energy-related derivative contracts were 621 million mmBtu and 500 million mmBtu for the years ended December 31, 2017 and 2016, respectively.
For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or during(below) market prices was approximately $0.15 per mmBtu as of December 31, 2017 and $(0.05) per mmBtu as of December 31, 2016. The majority of the currentnatural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.
At December 31, 2017 and 2016, substantially all of the Southern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the fair value hierarchy, and over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements |
| December 31, 2017 |
| Total Fair Value | | Maturity |
| | Year 1 | | Years 2&3 | | Years 4&5 |
| (in millions) |
Level 1 | $ | (148 | ) | | $ | (71 | ) | | $ | (59 | ) | | $ | (18 | ) |
Level 2 | (15 | ) | | (30 | ) | | 13 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (163 | ) | | $ | (101 | ) | | $ | (46 | ) | | $ | (16 | ) |
The Southern Company system is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Southern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
With the exception of Southern Company Gas' subsidiary, Atlanta Gas Light, and the Southern Company Gas wholesale gas services business, the Southern Company system is not exposed to concentrations of credit risk. Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 natural gas marketers in Georgia responsible for the retail sale of natural gas to end-use customers in Georgia. For 2017, the four largest natural gas marketers based on customer count accounted for 19% of Southern Company Gas' adjusted operating margin. Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2017, Southern Company Gas' wholesale gas services business' top 20 counterparties represented approximately 48%, or $203 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year.
Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.
Capital Requirements and Contractual Obligations
The Southern Company system's construction program is currently estimated to total approximately $9.4 billion for 2018, $9.3 billion for 2019, $8.4 billion for 2020, $7.0 billion for 2021, and $6.9 billion for 2022. These amounts include expenditures of approximately $1.2 billion, $1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $1.3 billion per year for identified unbudgeted reliability-related2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" herein for additional information.
The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be approximately $0.3 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.4 billion for 2018, 2019, 2020, 2021, and 2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that are incurred. Accrualscosts related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been designatedpreviously constructed, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements under "Nuclear Construction" for information regarding additional factors that may impact construction expenditures.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Southern Company system provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, leases, unrecognized tax benefits, pipeline charges, storage capacity, gas supply, asset management agreements, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
The Southern Company system's contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 3,865 |
| | $ | 6,293 |
| | $ | 5,206 |
| | $ | 32,610 |
| | $ | 47,974 |
|
Interest | 1,782 |
| | 3,286 |
| | 2,793 |
| | 27,535 |
| | 35,396 |
|
Preferred stock dividends of subsidiaries(b) | 16 |
| | 33 |
| | 33 |
| | — |
| | 82 |
|
Financial derivative obligations(c) | 493 |
| | 198 |
| | 37 |
| | 5 |
| | 733 |
|
Operating leases(d) | 149 |
| | 232 |
| | 178 |
| | 968 |
| | 1,527 |
|
Capital leases(d) | 39 |
| | 43 |
| | 20 |
| | 232 |
| | 334 |
|
Unrecognized tax benefits(e) | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
Pipeline charges, storage capacity, and gas supply(f) | 813 |
| | 968 |
| | 714 |
| | 2,294 |
| | 4,789 |
|
Asset management agreements(g) | 9 |
| | 6 |
| | — |
| | — |
| | 15 |
|
Purchase commitments — | | | | | | | | |
|
|
Capital(h) | 9,016 |
| | 16,905 |
| | 12,749 |
| | — |
| | 38,670 |
|
Fuel(i) | 3,156 |
| | 3,573 |
| | 1,927 |
| | 5,588 |
| | 14,244 |
|
Purchased power(j) | 424 |
| | 884 |
| | 886 |
| | 3,716 |
| | 5,910 |
|
Other(k) | 407 |
| | 713 |
| | 434 |
| | 2,745 |
| | 4,299 |
|
Trusts — | | | | | | | | |
|
|
Nuclear decommissioning(l) | 5 |
| | 11 |
| | 11 |
| | 94 |
| | 121 |
|
Pension and other postretirement benefit plans(m) | 137 |
| | 275 |
| | — |
| | — |
| | 412 |
|
Total | $ | 20,329 |
| | $ | 33,420 |
| | $ | 24,988 |
| | $ | 75,787 |
| | $ | 154,524 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Represents preferred stock of subsidiaries. Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | See Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and included in "Purchased power." |
| |
(e) | See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. |
| |
(f) | Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. |
| |
(g) | Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services. |
| |
(h) | The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information. |
| |
(i) | Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(j) | Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. |
| |
(k) | Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
| |
(l) | Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information. |
| |
(m) | The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be usedidentified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to offset storm charges. Additional accrualsdiffer materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the NDR will enhance Alabama Power'suncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
transmission constraints;
effects of inflation;
the ability to dealcontrol costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;
the ability to construct facilities in accordance with the financial effectsrequirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural disasters, promote system reliability,gas distribution and offset costs retail customers would otherwise bear.storage facilities and the successful performance of necessary corporate functions;
As revenue from the Rate NDR charge is recognized, an equal amount
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and maintenance expensesSubsidiary Companies 2017 Annual Report
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
litigation related to the NDRKemper County energy facility;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas and the potential sale of a 33% equity interest in substantially all of Southern Power's solar assets, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will also be recognized. As a result, greater than expected;
the Rate NDR charge will not have anability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an orderthe Southern Company system's business resulting from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balancecyber intrusion or physical attack and the unrecovered costs, associatedthreat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by Southern Company from time to time with site removalthe SEC.
Southern Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and closure associated with future unit retirements caused by environmental regulations. These costs2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Retail electric revenues | $ | 15,330 |
| | $ | 15,234 |
| | $ | 14,987 |
|
Wholesale electric revenues | 2,426 |
| | 1,926 |
| | 1,798 |
|
Other electric revenues | 681 |
| | 698 |
| | 657 |
|
Natural gas revenues | 3,791 |
| | 1,596 |
| | — |
|
Other revenues | 803 |
| | 442 |
| | 47 |
|
Total operating revenues | 23,031 |
| | 19,896 |
| | 17,489 |
|
Operating Expenses: | | | | | |
Fuel | 4,400 |
| | 4,361 |
| | 4,750 |
|
Purchased power | 863 |
| | 750 |
| | 645 |
|
Cost of natural gas | 1,601 |
| | 613 |
| | — |
|
Cost of other sales | 513 |
| | 260 |
| | — |
|
Other operations and maintenance | 5,481 |
| | 5,240 |
| | 4,416 |
|
Depreciation and amortization | 3,010 |
| | 2,502 |
| | 2,034 |
|
Taxes other than income taxes | 1,250 |
| | 1,113 |
| | 997 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 20,480 |
| | 15,267 |
| | 13,207 |
|
Operating Income | 2,551 |
| | 4,629 |
| | 4,282 |
|
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 160 |
| | 202 |
| | 226 |
|
Earnings from equity method investments | 106 |
| | 59 |
| | — |
|
Interest expense, net of amounts capitalized | (1,694 | ) | | (1,317 | ) | | (840 | ) |
Other income (expense), net | (55 | ) | | (93 | ) | | (39 | ) |
Total other income and (expense) | (1,483 | ) | | (1,149 | ) | | (653 | ) |
Earnings Before Income Taxes | 1,068 |
| | 3,480 |
| | 3,629 |
|
Income taxes | 142 |
| | 951 |
| | 1,194 |
|
Consolidated Net Income | 926 |
| | 2,529 |
| | 2,435 |
|
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | 45 |
| | 54 |
|
Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Consolidated Net Income Attributable to Southern Company | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Common Stock Data: | | | | | |
Earnings per share — | | | | | |
Basic | $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
|
Diluted | 0.84 |
| | 2.55 |
| | 2.59 |
|
Average number of shares of common stock outstanding — (in millions) | | | | | |
Basic | 1,000 |
| | 951 |
| | 910 |
|
Diluted | 1,008 |
| | 958 |
| | 914 |
|
The accompanying notes are being amortizedan integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and recovered over2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Consolidated Net Income | $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Other comprehensive income: | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $34, $(84), and $(8), respectively | 57 |
| | (136 | ) | | (13 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(37), $43, and $4, respectively | (60 | ) | | 69 |
| | 6 |
|
Pension and other postretirement benefit plans: | | | | | |
Benefit plan net gain (loss), net of tax of $6, $10, and $(1), respectively | 17 |
| | 13 |
| | (2 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(6), $3, and $4, respectively | (23 | ) | | 4 |
| | 7 |
|
Total other comprehensive income (loss) | (9 | ) | | (50 | ) | | (2 | ) |
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | 45 |
| | 54 |
|
Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 833 |
| | $ | 2,398 |
| | $ | 2,365 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the affected unit's remaining useful life, as established priorYears Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| | | (in millions) |
Operating Activities: | | | | | |
Consolidated net income | $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 3,457 |
| | 2,923 |
| | 2,395 |
|
Deferred income taxes | 166 |
| | (127 | ) | | 1,404 |
|
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Allowance for equity funds used during construction | (160 | ) | | (202 | ) | | (226 | ) |
Pension and postretirement funding | (2 | ) | | (1,029 | ) | | (7 | ) |
Settlement of asset retirement obligations | (177 | ) | | (171 | ) | | (37 | ) |
Stock based compensation expense | 109 |
| | 121 |
| | 99 |
|
Hedge settlements | 6 |
| | (233 | ) | | (17 | ) |
Estimated loss on Kemper IGCC | 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | (47 | ) | | (122 | ) | | (413 | ) |
Other, net | (109 | ) | | (99 | ) | | 49 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (199 | ) | | (544 | ) | | 243 |
|
-Fossil fuel for generation | 36 |
| | 178 |
| | 61 |
|
-Natural gas for sale | 36 |
| | (226 | ) | | — |
|
-Other current assets | (143 | ) | | (206 | ) | | (152 | ) |
-Accounts payable | (280 | ) | | 301 |
| | (353 | ) |
-Accrued taxes | (142 | ) | | 1,456 |
| | 352 |
|
-Retail fuel cost over recovery | (212 | ) | | (231 | ) | | 289 |
|
-Mirror CWIP | — |
| | — |
| | (271 | ) |
-Other current liabilities | (45 | ) | | 250 |
| | 58 |
|
Net cash provided from operating activities | 6,395 |
| | 4,894 |
| | 6,274 |
|
Investing Activities: | | | | | |
Business acquisitions, net of cash acquired | (1,070 | ) | | (10,689 | ) | | (1,719 | ) |
Property additions | (7,423 | ) | | (7,310 | ) | | (5,674 | ) |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | 1,682 |
| | — |
| | — |
|
Investment in restricted cash | (17 | ) | | (733 | ) | | (160 | ) |
Distribution of restricted cash | 34 |
| | 742 |
| | 154 |
|
Nuclear decommissioning trust fund purchases | (811 | ) | | (1,160 | ) | | (1,424 | ) |
Nuclear decommissioning trust fund sales | 805 |
| | 1,154 |
| | 1,418 |
|
Cost of removal, net of salvage | (313 | ) | | (245 | ) | | (167 | ) |
Change in construction payables, net | 259 |
| | (121 | ) | | 402 |
|
Investment in unconsolidated subsidiaries | (152 | ) | | (1,444 | ) | | — |
|
Payments pursuant to LTSAs | (227 | ) | | (134 | ) | | (197 | ) |
Other investing activities | 42 |
| | (108 | ) | | 87 |
|
Net cash used for investing activities | (7,191 | ) | | (20,048 | ) | | (7,280 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (401 | ) | | 1,228 |
| | 73 |
|
Proceeds — | | | | | |
Long-term debt | 5,858 |
| | 16,368 |
| | 7,029 |
|
Common stock | 793 |
| | 3,758 |
| | 256 |
|
Preferred stock | 250 |
| | — |
| | — |
|
Short-term borrowings | 1,259 |
| | — |
| | 755 |
|
Redemptions and repurchases — | | | | | |
Long-term debt | (2,930 | ) | | (3,145 | ) | | (3,604 | ) |
Common stock | — |
| | — |
| | (115 | ) |
Interest-bearing refundable deposits | — |
| | — |
| | (275 | ) |
Preferred and preference stock | (658 | ) | | — |
| | (412 | ) |
Short-term borrowings | (659 | ) | | (478 | ) | | (255 | ) |
Distributions to noncontrolling interests | (119 | ) | | (72 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Payment of common stock dividends | (2,300 | ) | | (2,104 | ) | | (1,959 | ) |
Other financing activities | (222 | ) | | (512 | ) | | (116 | ) |
Net cash provided from financing activities | 951 |
| | 15,725 |
| | 1,700 |
|
Net Change in Cash and Cash Equivalents | 155 |
| | 571 |
| | 694 |
|
Cash and Cash Equivalents at Beginning of Year | 1,975 |
| | 1,404 |
| | 710 |
|
Cash and Cash Equivalents at End of Year | $ | 2,130 |
| | $ | 1,975 |
| | $ | 1,404 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 2,130 |
| | $ | 1,975 |
|
Receivables — | | | |
Customer accounts receivable | 1,806 |
| | 1,583 |
|
Energy marketing receivable | 607 |
| | 623 |
|
Unbilled revenues | 810 |
| | 706 |
|
Under recovered fuel clause revenues | 171 |
| | — |
|
Income taxes receivable, current | 63 |
| | 544 |
|
Other accounts and notes receivable | 635 |
| | 377 |
|
Accumulated provision for uncollectible accounts | (44 | ) | | (43 | ) |
Materials and supplies | 1,438 |
| | 1,462 |
|
Fossil fuel for generation | 594 |
| | 689 |
|
Natural gas for sale | 595 |
| | 631 |
|
Prepaid expenses | 452 |
| | 364 |
|
Other regulatory assets, current | 604 |
| | 581 |
|
Other current assets | 211 |
| | 230 |
|
Total current assets | 10,072 |
| | 9,722 |
|
Property, Plant, and Equipment: | | | |
In service | 103,542 |
| | 98,416 |
|
Less: Accumulated depreciation | 31,457 |
| | 29,852 |
|
Plant in service, net of depreciation | 72,085 |
| | 68,564 |
|
Nuclear fuel, at amortized cost | 883 |
| | 905 |
|
Construction work in progress | 6,904 |
| | 8,977 |
|
Total property, plant, and equipment | 79,872 |
| | 78,446 |
|
Other Property and Investments: | | | |
Goodwill | 6,268 |
|
| 6,251 |
|
Equity investments in unconsolidated subsidiaries | 1,513 |
|
| 1,549 |
|
Other intangible assets, net of amortization of $186 and $62 at December 31, 2017 and December 31, 2016, respectively | 873 |
| | 970 |
|
Nuclear decommissioning trusts, at fair value | 1,832 |
| | 1,606 |
|
Leveraged leases | 775 |
| | 774 |
|
Miscellaneous property and investments | 249 |
| | 270 |
|
Total other property and investments | 11,510 |
| | 11,420 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 825 |
| | 1,629 |
|
Unamortized loss on reacquired debt | 206 |
| | 223 |
|
Other regulatory assets, deferred | 6,943 |
| | 6,851 |
|
Other deferred charges and assets | 1,577 |
| | 1,406 |
|
Total deferred charges and other assets | 9,551 |
| | 10,109 |
|
Total Assets | $ | 111,005 |
| | $ | 109,697 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 3,892 |
| | $ | 2,587 |
|
Notes payable | 2,439 |
| | 2,241 |
|
Energy marketing trade payables | 546 |
| | 597 |
|
Accounts payable | 2,530 |
| | 2,228 |
|
Customer deposits | 542 |
| | 558 |
|
Accrued taxes — | | | |
Accrued income taxes | 6 |
| | 193 |
|
Unrecognized tax benefits | 18 |
| | 385 |
|
Other accrued taxes | 613 |
| | 667 |
|
Accrued interest | 488 |
| | 518 |
|
Accrued compensation | 959 |
| | 915 |
|
Asset retirement obligations, current | 351 |
| | 378 |
|
Acquisitions payable | 5 |
| | 489 |
|
Other regulatory liabilities, current | 337 |
| | 236 |
|
Other current liabilities | 868 |
| | 925 |
|
Total current liabilities | 13,594 |
| | 12,917 |
|
Long-Term Debt (See accompanying statements) | 44,462 |
| | 42,629 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 6,842 |
| | 14,092 |
|
Deferred credits related to income taxes | 7,256 |
| | 219 |
|
Accumulated deferred ITCs | 2,267 |
| | 2,228 |
|
Employee benefit obligations | 2,256 |
| | 2,299 |
|
Asset retirement obligations, deferred | 4,473 |
| | 4,136 |
|
Accrued environmental remediation | 389 |
| | 397 |
|
Other cost of removal obligations | 2,684 |
| | 2,748 |
|
Other regulatory liabilities, deferred | 239 |
| | 258 |
|
Other deferred credits and liabilities | 691 |
| | 880 |
|
Total deferred credits and other liabilities | 27,097 |
| | 27,257 |
|
Total Liabilities | 85,153 |
| | 82,803 |
|
Redeemable Preferred Stock of Subsidiaries (See accompanying statements) | 324 |
| | 118 |
|
Redeemable Noncontrolling Interests (See accompanying statements) | — |
| | 164 |
|
Total Stockholders' Equity (See accompanying statements) | 25,528 |
| | 26,612 |
|
Total Liabilities and Stockholders' Equity | $ | 111,005 |
| | $ | 109,697 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| | | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | | (in millions) | | | (percent of total) |
Long-Term Debt: | | | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | | | $ | 206 |
| | $ | 206 |
| | | | |
Long-term senior notes and debt — | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | |
2017 | 1.30% to 7.20% | | — |
| | 2,019 |
| | | | |
2018 | 1.50% to 5.40% | | 2,402 |
| | 2,403 |
| | | | |
2019 | 1.85% to 5.55% | | 3,074 |
| | 3,076 |
| | | | |
2020 | 2.00% to 4.75% | | 2,273 |
| | 1,326 |
| | | | |
2021 | 2.35% to 9.10% | | 2,643 |
| | 2,655 |
| | | | |
2022 | 1.00% to 8.70% | | 2,016 |
| | 1,378 |
| | | | |
2023 through 2047 | 1.85% to 7.30% | | 22,142 |
| | 20,369 |
| | | | |
Variable rates (1.82% to 3.75% at 1/1/17) due 2017 | | | — |
| | 461 |
| | | | |
Variable rates (2.29% to 3.05% at 12/31/17) due 2018 | | | 1,420 |
| | 1,520 |
| | | | |
Variable rates (2.04% to 2.18% at 12/31/17) due 2020 | | | 825 |
| | — |
| | | | |
Variable rates (2.55% to 2.79% at 12/31/17) due 2021 | | | 25 |
| | 25 |
| | | | |
Variable rate (3.75% at 1/1/17) due 2032 to 2036 | | | — |
| | 15 |
| | | | |
Total long-term senior notes and debt | | | 36,820 |
| | 35,247 |
| | | | |
Other long-term debt — | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | |
2019 | 4.55% | | 25 |
| | 25 |
| | | | |
2022 | 2.10% to 2.35% | | 90 |
| | 90 |
| | | | |
2023 through 2049 | 1.15% to 5.15% | | 1,379 |
| | 1,339 |
| | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | | | 40 |
| | 76 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | | | 65 |
| | 65 |
| | | | |
Variable rates (1.83% to 1.84% at 12/31/17) due 2022 | | | 17 |
| | 17 |
| | | | |
Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053 | | | 1,680 |
| | 1,721 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | | | 270 |
| | 270 |
| | | | |
FFB loans — | | | | | | | | | |
2.57% to 3.86% due 2020 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2021 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2022 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2023 to 2044 | | | 2,493 |
| | 2,493 |
| | | | |
First mortgage bonds — | | | | | | | | | |
4.70% due 2019 | | | 50 |
| | 50 |
| | | | |
2.66% to 6.58% due 2023 to 2057 | | | 975 |
| | 575 |
| | | | |
Gas facility revenue bonds — | | | | | | | | | |
Variable rate (1.71% at 12/31/17) due 2022 | | | 47 |
| | 47 |
| | | | |
Variable rate (1.71% at 12/31/17) due 2024 to 2033 | | | 154 |
| | 154 |
| | | | |
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077 | | | 3,570 |
| | 2,350 |
| | | | |
Total other long-term debt | | | 10,987 |
| | 9,404 |
| | | | |
Unamortized fair value adjustment of long-term debt | | | 525 |
| | 578 |
| | | | |
Capitalized lease obligations | | | 204 |
| | 136 |
| | | | |
Unamortized debt premium | | | 44 |
| | 52 |
| | | | |
Unamortized debt discount | | | (206 | ) | | (194 | ) | | | | |
Unamortized debt issuance expense | | | (226 | ) | | (213 | ) | | | | |
Total long-term debt (annual interest requirement — $1.8 billion) | | 48,354 |
| | 45,216 |
| | | | |
Less amount due within one year | | | 3,892 |
| | 2,587 |
| | | | |
Long-term debt excluding amount due within one year | | | 44,462 |
| | 42,629 |
| | 63.2 | % | | 61.3 | % |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report | | | | | | | | |
| | | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | | (in millions) | | | (percent of total) |
Redeemable Preferred Stock of Subsidiaries: | | | | | | | | | |
Cumulative preferred stock | | | | | | | | | |
$100 par or stated value — 4.20% to 5.44% | | | | | | | | | |
Authorized — 20 million shares | | | | | | | | | |
Outstanding — 1 million shares | | | 324 |
| | 81 |
| | | | |
$1 par value — 5.83% | | | | | | | | | |
Authorized — 28 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares: $25 stated value | | | — |
| | 37 |
| | | | |
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $16 million) | | | 324 |
| | 118 |
| | 0.5 |
| | 0.2 |
|
Redeemable Noncontrolling Interests | | | — |
| | 164 |
| | — |
| | 0.2 |
|
Common Stockholders' Equity: | | | | | | | | | |
Common stock, par value $5 per share — | | | 5,038 |
| | 4,952 |
| | | | |
Authorized — 1.5 billion shares | | | | | | | | | |
Issued — 2017: 1.0 billion shares | | | | | | | | | |
— 2016: 991 million shares | | | | | | | | | |
Treasury — 2017: 0.9 million shares | | | | | | | | | |
— 2016: 0.8 million shares | | | | | | | | | |
Paid-in capital | | | 10,469 |
| | 9,661 |
| | | | |
Treasury, at cost | | | (36 | ) | | (31 | ) | | | | |
Retained earnings | | | 8,885 |
| | 10,356 |
| | | | |
Accumulated other comprehensive loss | | | (189 | ) | | (180 | ) | | | | |
Total common stockholders' equity | | | 24,167 |
| | 24,758 |
| | 34.4 |
| | 35.6 |
|
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests: | | | | | | | | | |
Non-cumulative preferred stock | | | | | | | | | |
$25 par value — 6.00% to 6.13% | | | | | | | | | |
Authorized — 60 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares | | | — |
| | 45 |
| | | | |
Non-cumulative preference stock | | | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | | | |
Authorized — 65 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | — |
| | 196 |
| | | | |
— 2016: 8 million shares | | | | | | | | | |
$100 par or stated value — 5.60% to 6.50% | | | | | | | | | |
Outstanding — 2017: no shares | | | — |
| | 368 |
| | | | |
— 2016: 4 million shares | | | | | | | | | |
Noncontrolling interests | | | 1,361 |
| | 1,245 |
| | | | |
Total preferred and preference stock of subsidiaries and noncontrolling interests | | | 1,361 |
| | 1,854 |
| | 1.9 |
| | 2.7 |
|
Total stockholders' equity | | | 25,528 |
| | 26,612 |
| | | | |
Total Capitalization | | | $ | 70,314 |
| | $ | 69,523 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern Company Common Stockholders' Equity | | | | | |
| Number of Common Shares | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Preferred and Preference Stock of Subsidiaries | | Noncontrolling Interests | |
| Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | | | Total |
| (in thousands) | | (in millions) |
Balance at December 31, 2014 | 908,502 |
| | (725 | ) | | $ | 4,539 |
| | $ | 5,955 |
| | $ | (26 | ) | | $ | 9,609 |
| | $ | (128 | ) | | $ | 756 |
| | $ | 221 |
| $ | 20,926 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 2,367 |
| | — |
| | — |
| | — |
| 2,367 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| (2 | ) |
Stock issued | 6,571 |
| | (2,599 | ) | | 33 |
| | 223 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 256 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 100 |
|
Stock repurchased, at cost | — |
| | — |
| | — |
| | — |
| | (115 | ) | | — |
| | — |
| | — |
| | — |
| (115 | ) |
Cash dividends of $2.1525 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (1,959 | ) | | — |
| | — |
| | — |
| (1,959 | ) |
Preference stock redemption | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (150 | ) | | — |
| (150 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | (18 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| 12 |
|
Other | — |
| | (28 | ) | | — |
| | 4 |
| | (1 | ) | | (7 | ) | | — |
| | 3 |
| | (1 | ) | (2 | ) |
Balance at December 31, 2015 | 915,073 |
| | (3,352 | ) | | 4,572 |
| | 6,282 |
| | (142 | ) | | 10,010 |
| | (130 | ) | | 609 |
| | 781 |
| 21,982 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 2,448 |
| | — |
| | — |
| | — |
| 2,448 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (50 | ) | | — |
| | — |
| (50 | ) |
Stock issued | 76,140 |
| | 2,599 |
| | 380 |
| | 3,263 |
| | 115 |
| | — |
| | — |
| | — |
| | — |
| 3,758 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 120 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 120 |
|
Cash dividends of $2.2225 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (2,104 | ) | | — |
| | — |
| | — |
| (2,104 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| 32 |
|
Other | — |
| | (66 | ) | | — |
| | (4 | ) | | (4 | ) | | 2 |
| | — |
| | — |
| | — |
| (6 | ) |
Balance at December 31, 2016 | 991,213 |
| | (819 | ) | | 4,952 |
| | 9,661 |
| | (31 | ) | | 10,356 |
| | (180 | ) | | 609 |
| | 1,245 |
| 26,612 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 842 |
| | — |
| | — |
| | — |
| 842 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (9 | ) | | — |
| | — |
| (9 | ) |
Stock issued | 17,319 |
| | — |
| | 86 |
| | 707 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 793 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 105 |
|
Cash dividends of $2.3000 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (2,300 | ) | | — |
| | — |
| | — |
| (2,300 | ) |
Preferred and preference stock redemptions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (609 | ) | | — |
| (609 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | (122 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| 114 |
|
Other | — |
| | (110 | ) | | — |
| | (4 | ) | | (5 | ) | | (13 | ) | | — |
| | — |
| | 1 |
| (21 | ) |
Balance at December 31, 2017 | 1,008,532 |
| | (929 | ) | | $ | 5,038 |
| | $ | 10,469 |
| | $ | (36 | ) | | $ | 8,885 |
| | $ | (189 | ) | | $ | — |
| | $ | 1,361 |
| $ | 25,528 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2017 Annual Report
Index to the decision regarding early retirement through Rate CNP Compliance.Notes to Financial Statements
|
| | |
Note | | Page |
1 | | |
2 | | |
3 | | |
4 | | |
5 | | |
6 | | |
7 | | |
8 | | |
9 | | |
10 | | |
11 | | |
12 | | |
13 | | |
14 | | |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
In April 2015, as part1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs). Additionally,natural gas distribution utilities.
The financial statements reflect Southern Company's investments in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain availablethe subsidiaries on a limited basis withconsolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas asdistribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the fuel source. Inconsolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the joint stipulation enteredaccounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in connectionconformity with a civil enforcement action byGAAP requires the EPA, Alabama Power retired Plant Barry Unit 3 (225 MWs)use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in August 2015 and it is no longer available for generation. Alabama Power expectsthe financial statements have been reclassified to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.
In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established priorconform to the decision for retirement. As a result, these decisions will not have a significantcurrent year presentation. These reclassifications had no impact on Southern Company's results of operations, financial statements.
Nuclear Waste Fund Accounting Orderposition, or cash flows.
In 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the U.S. District Court forsecond quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the Districteffects of Columbia orderedthis error on the DOEinterim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Actany affected period and, therefore, an amendment of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014.previously filed financial statements was not required.
Recently Issued Accounting Standards
Revenue
In August 2014, the Alabama PSCFASB issued an order to provideASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for the continued recoveryrevenue recognition with a five-step model for recognizing and measuring revenue from customers of amounts associatedcontracts with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for Alabama Power to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, Alabama Power transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense.
Cost of Removal Accounting Order
In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 millioncustomers. The underlying principle of the regulatory liability for other costnew standard is to recognize revenue to depict the transfer of removal obligations.goods or services to customers at the amount expected to be collected. The regulatory asset accounts fully amortizednew standard also requires enhanced disclosures regarding the nature, amount, timing, and terminated asuncertainty of December 31, 2014 represented costs previously deferred underrevenue and the related cash flows arising from contracts with customers.
Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a compliance and pension cost accounting orderdefined contractual term, as well as a non-nuclear outage accounting order, which were approved bylonger-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.
Southern Company has completed the Alabama PSC in 2012evaluation of all revenue streams and 2013, respectively. Approximately $95 milliondetermined that the adoption of non-nuclear outage costsASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and $28 millionalternative revenue programs, are excluded from the scope of complianceASC 606 and, pension costs were fully amortized in December 2014.
Georgia Power
Rate Plans
In 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors.
In January 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million.
On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million; (2) ECCR tariff by approximately $23 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $3 million, for a total increase in base revenues of approximately $136 million.
On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million.
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00%therefore, will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $11 million in 2016, as
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Regulatory Assets and Liabilities
The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 | | 2016 | | Note |
| (in millions) | | |
Retiree benefit plans | $ | 3,931 |
| | $ | 3,959 |
| | (a,n) |
Asset retirement obligations-asset | 1,133 |
| | 1,080 |
| | (b,n) |
Deferred income tax charges | 814 |
| | 1,590 |
| | (b,p) |
Environmental remediation-asset | 511 |
| | 491 |
| | (j,n) |
Property damage reserves-asset | 333 |
| | 206 |
| | (i) |
Under recovered regulatory clause revenues | 317 |
| | 273 |
| | (g) |
Remaining net book value of retired assets | 306 |
| | 351 |
| | (o) |
Loss on reacquired debt | 223 |
| | 243 |
| | (c) |
Vacation pay | 183 |
| | 182 |
| | (f,n) |
Long-term debt fair value adjustment | 138 |
| | 155 |
| | (d) |
Deferred PPA charges | 119 |
| | 141 |
| | (e,n) |
Kemper County energy facility | 88 |
| | 201 |
| | (h) |
Other regulatory assets | 511 |
| | 487 |
| | (k) |
Deferred income tax credits | (7,261 | ) | | (219 | ) | | (b,p) |
Other cost of removal obligations | (2,684 | ) | | (2,774 | ) | | (b) |
Over recovered regulatory clause revenues | (155 | ) | | (203 | ) | | (g) |
Property damage reserves-liability | (135 | ) | | (177 | ) | | (l) |
Other regulatory liabilities | (266 | ) | | (120 | ) | | (m) |
Total regulatory assets (liabilities), net | $ | (1,894 | ) | | $ | 5,866 |
| | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(b) | Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. |
| |
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. |
| |
(d) | Recovered over the remaining life of the original debt issuances, which range up to 21 years. For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas." |
| |
(e) | Recovered over the life of the PPA for periods up to six years. |
| |
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding 10 years. |
| |
(h) | Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." |
| |
(i) | Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information. |
| |
(j) | Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. |
| |
(k) | Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years. |
| |
(l) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. |
| |
(m) | Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years. |
| |
(n) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(o) | Amortized as approved by the appropriate state PSCs over periods generally up to 48 years. |
| |
(p) | As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional information. |
In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
are to be reflected in rates. See Note 3 under "Regulatory Matters – Alabama Power," " – Georgia Power," " – Gulf Power," and " – Southern Company Gas" and "Kemper County Energy Facility" for additional information.
Revenues
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. For the traditional electric operating companies, revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months. Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs.
Southern Company's electric utility subsidiaries and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production.
Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss" for additional information.
Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Electric utilities: | | | |
Generation | $ | 51,279 |
| | $ | 48,836 |
|
Transmission | 11,562 |
| | 11,156 |
|
Distribution | 19,239 |
| | 18,418 |
|
General | 4,276 |
| | 4,629 |
|
Plant acquisition adjustment | 126 |
| | 126 |
|
Electric utility plant in service | 86,482 |
| | 83,165 |
|
Natural gas distribution utilities: | | | |
Transportation and distribution | 13,078 |
| | 11,996 |
|
Utility plant in service | 99,560 |
| | 95,161 |
|
Information technology equipment and software | 752 |
| | 544 |
|
Communications equipment | 456 |
| | 424 |
|
Storage facilities | 1,598 |
| | 1,463 |
|
Other | 1,176 |
| | 824 |
|
Total other plant in service | 3,982 |
| | 3,255 |
|
Total plant in service | $ | 103,542 |
| | $ | 98,416 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs. In accordance with their respective state PSC orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle, which ranges from 18 to 24 months.
Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below:
|
| | | | | | | |
| Asset Balances at December 31, |
| 2017 |
| 2016 |
| (in millions) |
Office buildings | $ | 216 |
|
| $ | 61 |
|
Nitrogen plant(*) | — |
|
| 83 |
|
Computer-related equipment | 51 |
|
| 63 |
|
Gas pipeline | 6 |
|
| 6 |
|
Less: Accumulated amortization | (72 | ) |
| (69 | ) |
Balance, net of amortization | $ | 201 |
|
| $ | 144 |
|
| |
(*) | Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. |
The amount of non-cash property additions recognized for the years ended December 31, 2017, 2016, and 2015 was $985 million, $1.3 billion, and $844 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2017, 2016, and 2015 was $162 million, $18 million, and $13 million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2017 and 3.0% in each of 2016 and 2015. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $30.8 billion and $29.3 billion at December 31, 2017 and 2016, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations.
See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from two to 65 years. Accumulated depreciation for other plant in service totaled $673 million and $550 million at December 31, 2017 and 2016, respectively.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of the AROs included in the balance sheets are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Balance at beginning of year | $ | 4,514 |
| | $ | 3,759 |
|
Liabilities incurred | 16 |
| | 66 |
|
Liabilities settled | (177 | ) | | (171 | ) |
Accretion | 179 |
| | 162 |
|
Cash flow revisions | 292 |
| | 698 |
|
Balance at end of year | $ | 4,824 |
| | $ | 4,514 |
|
In 2017 and 2016, the increases in cash flow revisions are primarily related to changes in closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2017 and 2016, approximately $76 million and $56 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $77 million and $58 million at December 31, 2017 and 2016, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
At December 31, 2017, investment securities in the Funds totaled $1.8 billion, consisting of equity securities of $1.1 billion, debt securities of $725 million, and $47 million of other securities. At December 31, 2016, investment securities in the Funds totaled $1.6 billion, consisting of equity securities of $878 million, debt securities of $685 million, and $41 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the securities lending program.
Sales of the securities held in the Funds resulted in cash proceeds of $0.8 billion, $1.2 billion, and $1.4 billion in 2017, 2016, and 2015, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $233 million, which included $181 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million, which included $48 million related to unrealized losses on securities held in the Funds at
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $11 million, which included $83 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
For Alabama Power, approximately $18 million and $19 million at December 31, 2017 and 2016, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, 2017 and 2016, the accumulated provisions for the external decommissioning trust funds were as follows:
|
| | | | | | | |
| External Trust Funds |
| 2017 | | 2016 |
| (in millions) |
Plant Farley | $ | 902 |
| | $ | 790 |
|
Plant Hatch | 583 |
| | 511 |
|
Plant Vogtle Units 1 and 2 | 346 |
| | 303 |
|
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:
|
| | | | | | | | | | | |
| Plant Farley | | Plant Hatch | | Plant Vogtle Units 1 and 2 |
Decommissioning periods: | | | | | |
Beginning year | 2037 |
| | 2034 |
| | 2047 |
|
Completion year | 2076 |
| | 2075 |
| | 2079 |
|
| (in millions) |
Site study costs: | | | | | |
Radiated structures | $ | 1,362 |
| | $ | 678 |
| | $ | 568 |
|
Spent fuel management | — |
| | 160 |
| | 147 |
|
Non-radiated structures | 80 |
| | 64 |
| | 89 |
|
Total site study costs | $ | 1,442 |
| | $ | 902 |
| | $ | 804 |
|
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power's 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Allowance for Funds Used During Construction and Interest Capitalized
The traditional electric operating companies and certain of the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes, as a percentage of net income, was 25.5%, 11.4%, and 12.8% for 2017, 2016, and 2015, respectively.
Cash payments for interest totaled $1.7 billion, $1.1 billion, and $809 million in 2017, 2016, and 2015, respectively, net of amounts capitalized of $89 million, $125 million, and $124 million, respectively.
Impairment of Long-Lived Assets
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See "Leveraged Leases" herein and Note 3 under "Other Matters" and "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
Goodwill and Other Intangible Assets and Liabilities
Southern Company's goodwill and other intangible assets and liabilities primarily relate to Southern Company's 2016 acquisitions of PowerSecure and Southern Company Gas. See Note 12 under "Southern Company – Acquisition of PowerSecure" and " – Merger with Southern Company Gas" for additional information. Also see Note 12 under "Southern Power" for additional information regarding other intangible assets related to Southern Power's PPA fair value adjustments.
At December 31, 2017 and 2016, goodwill was $6.3 billion. Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company evaluated its goodwill in the fourth quarter 2017 and determined that no impairment was required.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | At December 31, 2017 | | At December 31, 2016 |
| Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | (in millions) | | (in millions) |
Other intangible assets subject to amortization: | | | | | | | | |
Customer relationships | 11-26 years | $ | 288 |
| $ | (83 | ) | $ | 205 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
Trade names | 5-28 years | 159 |
| (17 | ) | 142 |
| | 158 |
| (5 | ) | 153 |
|
Storage and transportation contracts | 1-5 years | 64 |
| (34 | ) | 30 |
| | 64 |
| (2 | ) | 62 |
|
PPA fair value adjustments | 10-20 years | 456 |
| (47 | ) | 409 |
| | 456 |
| (22 | ) | 434 |
|
Other | 1-12 years | 17 |
| (5 | ) | 12 |
| | 11 |
| (1 | ) | 10 |
|
Total other intangible assets subject to amortization | | $ | 984 |
| $ | (186 | ) | $ | 798 |
|
| $ | 957 |
| $ | (62 | ) | $ | 895 |
|
Other intangible assets not subject to amortization: | | | | | | | | |
Federal Communications Commission licenses | | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
Total other intangible assets | | $ | 1,059 |
| $ | (186 | ) | $ | 873 |
|
| $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
Amortization associated with other intangible assets in 2017, 2016, and 2015 totaled $124 million, $50 million, and $3 million, respectively.
As of December 31, 2017, the estimated amortization associated with other intangible assets for the next five years is as follows:
|
| | | |
| Amortization |
| (in millions) |
2018 | $ | 95 |
|
2019 | 77 |
|
2020 | 65 |
|
2021 | 56 |
|
2022 | 51 |
|
Included in other deferred credits and liabilities on the balance sheet is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at Southern Company Gas. At December 31, 2017, the accumulated amortization of these intangible liabilities was $50 million. The remaining estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: |
| | | |
| Amortization |
| (in millions) |
2018 | $ | 24 |
|
2019 | 17 |
|
Storm Damage Reserves
Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $41 million in 2017 and $40 million in each of 2016 and 2015. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2017, 2016, and 2015, there were no such additional accruals. See Note 3 under "Regulatory Matters – Alabama Power – Rate NDR" and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
"Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively.
Leveraged Leases
A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Net rentals receivable | $ | 1,498 |
| | $ | 1,481 |
|
Unearned income | (723 | ) | | (707 | ) |
Investment in leveraged leases | 775 |
| | 774 |
|
Deferred taxes from leveraged leases | (252 | ) | | (309 | ) |
Net investment in leveraged leases | $ | 523 |
| | $ | 465 |
|
A summary of the components of income from the leveraged leases follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Pretax leveraged lease income | $ | 25 |
| | $ | 25 |
| | $ | 20 |
|
Net impact of Tax Reform Legislation | 48 |
| | — |
| | — |
|
Income tax expense | (9 | ) | | (9 | ) | | (7 | ) |
Net leveraged lease income | $ | 64 |
| | $ | 16 |
| | $ | 13 |
|
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Natural Gas for Sale
The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
Financial Instruments
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.
The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2017, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.
Southern Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | | | |
| Qualifying Hedges | | Pension and Other Postretirement Benefit Plans | | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | (115 | ) | | $ | (65 | ) | | $ | (180 | ) |
Current period change | (4 | ) | | (5 | ) | | (9 | ) |
Balance at December 31, 2017 | $ | (119 | ) | | $ | (70 | ) | | $ | (189 | ) |
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. This qualified pension plan is funded in accordance with requirements of ERISA. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2017 | | 2016 | | 2015 |
Pension plans | | | | | |
Discount rate – benefit obligations | 4.40 | % | | 4.58 | % | | 4.17 | % |
Discount rate – interest costs | 3.77 |
| | 3.88 |
| | 4.17 |
|
Discount rate – service costs | 4.81 |
| | 4.98 |
| | 4.48 |
|
Expected long-term return on plan assets | 7.92 |
| | 8.16 |
| | 8.20 |
|
Annual salary increase | 4.37 |
| | 4.37 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – benefit obligations | 4.23 | % | | 4.38 | % | | 4.04 | % |
Discount rate – interest costs | 3.54 |
| | 3.66 |
| | 4.04 |
|
Discount rate – service costs | 4.64 |
| | 4.85 |
| | 4.39 |
|
Expected long-term return on plan assets | 6.84 |
| | 6.66 |
| | 6.97 |
|
Annual salary increase | 4.37 |
| | 4.37 |
| | 3.59 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 |
| 2016 |
Pension plans |
|
|
|
Discount rate | 3.80 | % |
| 4.40 | % |
Annual salary increase | 4.32 |
|
| 4.37 |
|
Other postretirement benefit plans |
|
|
|
Discount rate | 3.68 | % |
| 4.23 | % |
Annual salary increase | 4.32 |
|
| 4.37 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of eight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
|
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 132 |
| | $ | 113 |
|
Service and interest costs | 4 |
| | 3 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Pension Plans
The total accumulated benefit obligation for the pension plans was $12.6 billion at December 31, 2017 and $11.3 billion at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 12,385 |
| | $ | 10,542 |
|
Acquisitions | — |
| | 1,244 |
|
Service cost | 293 |
| | 262 |
|
Interest cost | 455 |
| | 422 |
|
Benefits paid | (596 | ) | | (466 | ) |
Plan amendments | (26 | ) | | 39 |
|
Actuarial (gain) loss | 1,297 |
| | 342 |
|
Balance at end of year | 13,808 |
| | 12,385 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 11,583 |
| | 9,234 |
|
Acquisitions | — |
| | 837 |
|
Actual return (loss) on plan assets | 1,953 |
| | 902 |
|
Employer contributions | 52 |
| | 1,076 |
|
Benefits paid | (596 | ) | | (466 | ) |
Fair value of plan assets at end of year | 12,992 |
| | 11,583 |
|
Accrued liability | $ | (816 | ) | | $ | (802 | ) |
At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $13.2 billion and $652 million, respectively. All pension plan assets are related to the qualified pension plans.
Amounts presented in the following tables exclude regulatory assets of $334 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 3,273 |
| | $ | 3,207 |
|
Other current liabilities | (53 | ) | | (53 | ) |
Employee benefit obligations | (763 | ) | | (749 | ) |
Other regulatory liabilities, deferred | (118 | ) | | (87 | ) |
Accumulated OCI | 107 |
| | 100 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| Prior Service Cost | | Net (Gain) Loss |
| (in millions) |
Balance at December 31, 2017: | | | |
Accumulated OCI | $ | 3 |
| | $ | 104 |
|
Regulatory assets | 14 |
| | 3,140 |
|
Total | $ | 17 |
| | $ | 3,244 |
|
Balance at December 31, 2016: | | | |
Accumulated OCI | $ | 4 |
| | $ | 96 |
|
Regulatory assets | 51 |
| | 3,069 |
|
Total | $ | 55 |
| | $ | 3,165 |
|
Estimated amortization in net periodic pension cost in 2018: | | | |
Accumulated OCI | $ | 1 |
| | $ | 9 |
|
Regulatory assets | 4 |
| | 204 |
|
Total | $ | 5 |
| | $ | 213 |
|
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| Accumulated OCI | | Regulatory Assets |
| (in millions) |
Balance at December 31, 2015 | $ | 125 |
| | $ | 2,998 |
|
Net (gain) loss | (20 | ) | | 243 |
|
Change in prior service costs | 2 |
| | 37 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (13 | ) |
Amortization of net gain (loss) | (6 | ) | | (145 | ) |
Total reclassification adjustments | (7 | ) | | (158 | ) |
Total change | (25 | ) | | 122 |
|
Balance at December 31, 2016 | $ | 100 |
| | $ | 3,120 |
|
Net (gain) loss | 15 |
| | 227 |
|
Change in prior service costs | — |
| | (26 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (11 | ) |
Amortization of net gain (loss) | (7 | ) | | (155 | ) |
Total reclassification adjustments | (8 | ) | | (166 | ) |
Total change | 7 |
| | 35 |
|
Balance at December 31, 2017 | $ | 107 |
| | $ | 3,155 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 293 |
| | $ | 262 |
| | $ | 257 |
|
Interest cost | 455 |
| | 422 |
| | 445 |
|
Expected return on plan assets | (897 | ) | | (782 | ) | | (724 | ) |
Recognized net (gain) loss | 162 |
| | 150 |
| | 215 |
|
Net amortization | 12 |
| | 14 |
| | 25 |
|
Net periodic pension cost | $ | 25 |
| | $ | 66 |
| | $ | 218 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 634 |
|
2019 | 637 |
|
2020 | 663 |
|
2021 | 681 |
|
2022 | 704 |
|
2023 to 2027 | 3,836 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 2,297 |
| | $ | 1,989 |
|
Acquisitions | — |
| | 338 |
|
Service cost | 24 |
| | 22 |
|
Interest cost | 79 |
| | 76 |
|
Benefits paid | (136 | ) | | (119 | ) |
Actuarial (gain) loss | 65 |
| | (16 | ) |
Plan amendments | 3 |
| | — |
|
Retiree drug subsidy | 7 |
| | 7 |
|
Balance at end of year | 2,339 |
| | 2,297 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 944 |
| | 833 |
|
Acquisitions | — |
| | 100 |
|
Actual return (loss) on plan assets | 154 |
| | 58 |
|
Employer contributions | 84 |
| | 65 |
|
Benefits paid | (129 | ) | | (112 | ) |
Fair value of plan assets at end of year | 1,053 |
| | 944 |
|
Accrued liability | $ | (1,286 | ) | | $ | (1,353 | ) |
Amounts presented in the following tables exclude regulatory assets of $77 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 382 |
| | $ | 419 |
|
Other current liabilities | (5 | ) | | (4 | ) |
Employee benefit obligations | (1,281 | ) | | (1,349 | ) |
Other regulatory liabilities, deferred | (41 | ) | | (41 | ) |
Accumulated OCI | 4 |
| | 7 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| Prior Service Cost | | Net (Gain) Loss |
| (in millions) |
Balance at December 31, 2017: | | | |
Accumulated OCI | $ | — |
| | $ | 4 |
|
Net regulatory assets | 21 |
| | 320 |
|
Total | $ | 21 |
| | $ | 324 |
|
Balance at December 31, 2016: | | | |
Accumulated OCI | $ | — |
| | $ | 7 |
|
Net regulatory assets | 25 |
| | 353 |
|
Total | $ | 25 |
| | $ | 360 |
|
Estimated amortization as net periodic postretirement benefit cost in 2018: | | | |
Net regulatory assets | $ | 7 |
| | $ | 14 |
|
The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| Accumulated OCI | | Net Regulatory Assets (Liabilities) |
| (in millions) |
Balance at December 31, 2015 | $ | 8 |
| | $ | 411 |
|
Net (gain) loss | (1 | ) | | (13 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | (6 | ) |
Amortization of net gain (loss) | — |
| | (14 | ) |
Total reclassification adjustments | — |
| | (20 | ) |
Total change | (1 | ) | | (33 | ) |
Balance at December 31, 2016 | $ | 7 |
| | $ | 378 |
|
Net (gain) loss | (3 | ) | | (21 | ) |
Change in prior service costs | — |
| | 3 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | (6 | ) |
Amortization of net gain (loss) | — |
| | (13 | ) |
Total reclassification adjustments | — |
| | (19 | ) |
Total change | (3 | ) | | (37 | ) |
Balance at December 31, 2017 | $ | 4 |
| | $ | 341 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 24 |
| | $ | 22 |
| | $ | 23 |
|
Interest cost | 79 |
| | 76 |
| | 78 |
|
Expected return on plan assets | (66 | ) | | (60 | ) | | (58 | ) |
Net amortization | 20 |
| | 21 |
| | 21 |
|
Net periodic postretirement benefit cost | $ | 57 |
| | $ | 59 |
| | $ | 64 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2018 | $ | 144 |
| | $ | (7 | ) | | $ | 137 |
|
2019 | 148 |
| | (8 | ) | | 140 |
|
2020 | 151 |
| | (8 | ) | | 143 |
|
2021 | 154 |
| | (9 | ) | | 145 |
|
2022 | 156 |
| | (9 | ) | | 147 |
|
2023 to 2027 | 780 |
| | (48 | ) | | 732 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The investment strategy for plan assets related to the Company's qualified pension plans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Investment Strategies and Benefit Plan Asset Fair Values
A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:
|
| |
Description | Valuation Methodology |
● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. |
● Fixed income: A mix of domestic and international bonds. | Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. |
● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. |
● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature.
● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. |
The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan (excluding Southern Company Gas) as of December 31, 2017 and 2016 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 2,405 |
| $ | 1,159 |
| $ | — |
| $ | — |
| $ | 3,564 |
| 26 | % | 31 | % |
International equity(*) | 1,555 |
| 1,403 |
| — |
| — |
| 2,958 |
| 25 |
| 25 |
|
Fixed income: | | | | | | 23 |
| 24 |
|
U.S. Treasury, government, and agency bonds | — |
| 841 |
| — |
| — |
| 841 |
|
|
|
Mortgage- and asset-backed securities | — |
| 8 |
| — |
| — |
| 8 |
|
|
|
Corporate bonds | — |
| 1,201 |
| — |
| — |
| 1,201 |
|
|
|
Pooled funds | — |
| 650 |
| — |
| — |
| 650 |
|
|
|
Cash equivalents and other | 217 |
| 11 |
| — |
| — |
| 228 |
|
|
|
Real estate investments | 469 |
| — |
| — |
| 1,188 |
| 1,657 |
| 14 |
| 13 |
|
Special situations | — |
| — |
| — |
| 180 |
| 180 |
| 3 |
| 1 |
|
Private equity | — |
| — |
| — |
| 669 |
| 669 |
| 9 |
| 6 |
|
Total | $ | 4,646 |
| $ | 5,273 |
| $ | — |
| $ | 2,037 |
| $ | 11,956 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 2,010 |
| $ | 927 |
| $ | — |
| $ | — |
| $ | 2,937 |
| 26 | % | 29 | % |
International equity(*) | 1,231 |
| 1,110 |
| — |
| — |
| 2,341 |
| 25 |
| 22 |
|
Fixed income: | | | | | | 23 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 588 |
| — |
| — |
| 588 |
|
|
|
Mortgage- and asset-backed securities | — |
| 13 |
| — |
| — |
| 13 |
|
|
|
Corporate bonds | — |
| 991 |
| — |
| — |
| 991 |
|
|
|
Pooled funds | — |
| 524 |
| — |
| — |
| 524 |
|
|
|
Cash equivalents and other | 996 |
| 2 |
| — |
| — |
| 998 |
|
|
|
Real estate investments | 310 |
| — |
| — |
| 1,152 |
| 1,462 |
| 14 |
| 13 |
|
Special situations | — |
| — |
|
|
| 180 |
| 180 |
| 3 |
| 2 |
|
Private equity | — |
| — |
| — |
| 549 |
| 549 |
| 9 |
| 5 |
|
Total | $ | 4,547 |
| $ | 4,155 |
| $ | — |
| $ | 1,881 |
| $ | 10,583 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 155 |
| $ | 323 |
| $ | — |
| $ | — |
| $ | 478 |
|
International equity(*) | — |
| 166 |
| — |
| — |
| 166 |
|
Fixed income: | | | | | |
U.S. Treasury, government, and agency bonds | — |
| 85 |
| — |
| — |
| 85 |
|
Corporate bonds | — |
| 39 |
| — |
| — |
| 39 |
|
Cash equivalents and other | 84 |
| 25 |
| — |
| 48 |
| 157 |
|
Real estate investments | 3 |
| — |
| — |
| 16 |
| 19 |
|
Private equity | — |
| — |
| — |
| 1 |
| 1 |
|
Total | $ | 242 |
| $ | 638 |
| $ | — |
| $ | 65 |
| $ | 945 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 142 |
| $ | 343 |
| $ | — |
| $ | — |
| $ | 485 |
|
International equity(*) | — |
| 185 |
| — |
| — |
| 185 |
|
Fixed income: |
|
|
|
|
|
U.S. Treasury, government, and agency bonds | — |
| 85 |
| — |
| — |
| 85 |
|
Corporate bonds | — |
| 41 |
| — |
| — |
| 41 |
|
Pooled funds | — |
| 66 |
| — |
| — |
| 66 |
|
Cash equivalents and other | 12 |
| 5 |
| — |
| 83 |
| 100 |
|
Real estate investments | 4 |
| — |
| — |
| 15 |
| 19 |
|
Private equity | — |
| — |
| — |
| 2 |
| 2 |
|
Total | $ | 158 |
| $ | 725 |
| $ | — |
| $ | 100 |
| $ | 983 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | |
Equity | | 53 | % | | 65 | % | | 69 | % |
Fixed Income | | 15 |
| | 19 |
| | 20 |
|
Cash | | 2 |
| | 6 |
| | 1 |
|
Other | | 30 |
| | 10 |
| | 10 |
|
Balance at end of period | | 100 | % | | 100 | % | | 100 | % |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 132 |
| $ | 35 |
| $ | — |
| $ | — |
| $ | 167 |
| 37 | % | 40 | % |
International equity(*) | 47 |
| 76 |
| — |
| — |
| 123 |
| 23 |
| 23 |
|
Fixed income: | | | | | | 30 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 32 |
| — |
| — |
| 32 |
|
|
|
Corporate bonds | — |
| 37 |
| — |
| — |
| 37 |
|
|
|
Pooled funds | — |
| 55 |
| — |
| — |
| 55 |
|
|
|
Cash equivalents and other | 10 |
| — |
| — |
| — |
| 10 |
|
|
|
Trust-owned life insurance | — |
| 426 |
| — |
| — |
| 426 |
|
|
|
Real estate investments | 16 |
| — |
| — |
| 36 |
| 52 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 20 |
| 20 |
| 4 |
| 2 |
|
Total | $ | 205 |
| $ | 661 |
| $ | — |
| $ | 61 |
| $ | 927 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 118 |
| $ | 28 |
| $ | — |
| $ | — |
| $ | 146 |
| 39 | % | 40 | % |
International equity(*) | 37 |
| 61 |
| — |
| — |
| 98 |
| 23 |
| 21 |
|
Fixed income: | | | | | | 29 |
| 31 |
|
U.S. Treasury, government, and agency bonds | — |
| 24 |
| — |
| — |
| 24 |
|
|
|
Corporate bonds | — |
| 30 |
| — |
| — |
| 30 |
|
|
|
Pooled funds | — |
| 49 |
| — |
| — |
| 49 |
|
|
|
Cash equivalents and other | 41 |
| — |
| — |
| — |
| 41 |
|
|
|
Trust-owned life insurance | — |
| 382 |
| — |
| — |
| 382 |
|
|
|
Real estate investments | 11 |
| — |
| — |
| 35 |
| 46 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 17 |
| 17 |
| 3 |
| 2 |
|
Total | $ | 207 |
| $ | 574 |
| $ | — |
| $ | 57 |
| $ | 838 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 69 |
| $ | — |
| $ | — |
| $ | 72 |
|
International equity(*) | — |
| 22 |
| — |
| — |
| 22 |
|
Fixed income: | | | | |
|
|
Pooled funds | — |
| 24 |
| — |
| — |
| 24 |
|
Cash equivalents and other | 2 |
| — |
| — |
| 1 |
| 3 |
|
Total | $ | 5 |
| $ | 115 |
| $ | — |
| $ | 1 |
| $ | 121 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 58 |
| $ | — |
| $ | — |
| $ | 61 |
|
International equity(*) | — |
| 18 |
| — |
| — |
| 18 |
|
Fixed income: | | | | | |
Pooled funds | — |
| 23 |
| — |
| — |
| 23 |
|
Cash equivalents and other | 1 |
| — |
| — |
| 2 |
| 3 |
|
Total | $ | 4 |
| $ | 99 |
| $ | — |
| $ | 2 |
| $ | 105 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Other postretirement benefit plan assets: | | | | | | |
Equity | | 72 | % | | 76 | % | | 74 | % |
Fixed Income | | 24 |
| | 20 |
| | 23 |
|
Cash | | 1 |
| | 2 |
| | 1 |
|
Other | | 3 |
| | 2 |
| | 2 |
|
Total | | 100 | % | | 100 | % | | 100 | % |
Employee Savings Plan
Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2017, 2016, and 2015 were $118 million, $105 million, and $92 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 18, 2016.27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million and $44 million as of December 31, 2017 and 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
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Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on Southern Company's financial statements.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. Also in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, no material impact on Southern Company's net income is expected.
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional
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electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
Alabama Power
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, Alabama Power's retail ROEreturn exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail ROE range.rates under Rate RSE remained unchanged for 2018.
GeorgiaIn conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is requiredexpected in 2018. As of December 31, 2017 and 2016, Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to filereduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a general base rate case by July 1, 2016, in response toseparate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which the Georgia PSC would beis expected to determine whetheroccur within the 2013 ARP shouldnext two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
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Rate CNP Compliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be continued, modified,recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or discontinued.net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.
Integrated Resource Plan
To comply with the April 16, 2015 effective dateSee "Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of the MATS rule, Plant Branch Units 1, 3,CCR and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and CO2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015..
In the 2013 ARP,July 2016, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.
On January 29, 2016, Georgia Power filed itsPower's triennial IRPIntegrated Resource Plan (2016 IRP). The filing included a request to decertify including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval, as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, IRP. The 2016 IRP also reflects thatthe Plant Mitchell and Plant Kraft units were retired and Georgia Power exercised its contractual option to sellsold its 33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information.LLC.
InAdditionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia Power requestedPSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. Georgia Power also requested that the Georgia PSC approve the deferral of the costand costs associated with materials and supplies remaining at the unit retirement datesdate to a regulatory asset,asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be amortized overin operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a period deemed appropriatefuture generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC.PSC in a future Georgia Power rate case.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The decertificationincremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory
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asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million. The rate of these unitsstorm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements; however,statements. See Note 3 to the financial statements under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.
Gulf Power
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome dependsof these matters cannot be determined at this time.
Mississippi Power
On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia PSC's orders in the 2016 IRP and next general base rate case.handle customer billing functions. Atlanta Gas Light earns revenue for its
Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting
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distribution services by charging rates to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand Georgia Power's existing renewable initiatives, including the Advanced Solar Initiative.
A decision fromits customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025. The total expected investment under these programs for 2018 is $395 million.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the 2016 IRP is expectedrevised requested increase in the thirdsecond quarter 2016. 2018.
The ultimate outcome of these matters cannot be determined at this time.
Fuel Cost Recovery
Georgia Power hasThe traditional electric operating companies each have established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program, as approved by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15, 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016.
Georgia Power's over recovered fuel balance totaled approximately $116 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014, Georgia Power's under recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets.
their respective state PSCs. Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Storm Damage Recovery
See Note 1 to the financial statements under "Revenues" and Note 3 to the financial statements under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power defers – Fuel Cost Recovery" for additional information.
Kemper County Energy Facility
The Kemper County energy facility was approved by the Mississippi PSC as an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of the Initial DOE Grants and recovers certain costsexcluding the Cost Cap Exceptions. The combined cycle and associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued the In-Service Asset Rate Order, authorizing rates that provided for the recovery of approximately $126 million annually related to damages from major stormsthe assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through basea natural
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rates. Asgas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The Kemper Settlement Order established the Kemper Settlement Docket for the purposes of pursuing a global settlement of the related costs.
On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine.
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2015 and2017. In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2014, the balance in the regulatory asset related to storm damage was $92 million and $98 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62 million and $68 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. 2017.
As a result of the regulatory treatment, costsMississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to storms are generally not expectedthe Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the
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plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial statements.condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop and other related parties and the arbitration was dismissed.
Construction Program
Overview
The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. The Southern Company system's construction program is currently estimated to total approximately $9.4 billion, $9.3 billion, $8.4 billion, $7.0 billion, and $6.9 billion for 2018, 2019, 2020, 2021, and 2022, respectively.
The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements under "Nuclear Construction" for additional information. See Note 12 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities. See Note 3 to the financial statements under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Nuclear Construction
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners),Owners, entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement).
Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. TheUnder the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, also providesToshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for liquidated damages upona schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's failuremotion seeking authorization to fulfill(i) enter into the scheduleVogtle Services Agreement, (ii) assume and performance guarantees, subjectassign to a cap. In addition,the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, provides for limited cost sharingbecame effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable toupon 30 days' written notice.
Effective October 23, 2017, Georgia Power, (basedacting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Georgia Power's ownership interest) of approximately $114 million.Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (and not(not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the ContractorBechtel under the Vogtle 3 and 4Bechtel Agreement. Georgia Power's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
The Vogtle Owners may terminate the Vogtle 3 and 4Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination costs. The Contractortermination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Vogtle 3 and 4Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspension or delayssuspensions of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In 2009,On November 2, 2017, the NRC issuedVogtle Owners entered into an Early Site Permit and Limited Work Authorization which allowed limited workamendment to begin ontheir joint ownership agreements for Plant Vogtle Units 3 and 4. The NRC certified4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Westinghouse Design Control Document, as amended (DCD), forVogtle Joint Ownership Agreements, the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receiptholders of at least 90% of the COLs allowed fullownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction to begin. There have been technical and procedural challengesif certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction and licensing of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the federalprimary construction contractor and state level,(ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and additional challenges may arise as construction proceeds.Subsidiary Companies 2017 Annual Report
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4.4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base during the construction period. Thecertified capital cost of $4.418 billion. As of December 31, 2017, Georgia PSC approved an initial NCCR tariffPower had recovered approximately $1.6 billion of approximately $223 million effectivefinancing costs. On January 1, 2011, as well as increases30, 2018, Georgia Power filed to decrease the NCCR tariff ofby approximately $35 million, $50 million, $60 million, $27effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and $19 million effective January 1, 2012, 2013, 2014, 2015,the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and 2016, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM)VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On April 15, 2015,December 20, 2016, the Georgia PSC issuedvoted to approve a procedural ordersettlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the twelfthfifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report which included a requested amendment (Requested Amendment)and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to the Plant Vogtle Units 3 and 4 certificate to reflect4: (i) none of the Contractor's revised forecast for completion$3.3 billion of Plant Vogtle Units 3costs incurred through December 31, 2015 and 4 (second quarterreflected in the fourteenth VCM report should be disallowed from rate base on the basis of 2019imprudence; (ii) the Contractor Settlement Agreement was reasonable and second quarterprudent and none of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuantamounts paid pursuant to the Georgia PSC's procedural order,Contractor Settlement Agreement should be disallowed from rate base on the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completionbasis of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, anyimprudence; (iii) (a) capital costs incurred by Georgia Power in excess of the certified amount willup to $5.680 billion would be included in rate base, provided Georgia Power shows the costspresumed to be reasonable and prudent. Financing costs up toprudent with the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costsburden of proof on any construction-relatedparty challenging such costs, in excess(b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the $4.4 billion certified amount are expected to be recovered through AFUDC.
In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timingimpact of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costspayments received under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The ContractorGuarantee Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4;Customer Refunds) is found reasonable; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, Georgia Power paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that occurredthe revised cost forecast does not represent a cost cap and that prudence decisions on orcost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the dateBipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.PTCs is approximately $500 million per unit.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
OnIn its January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to11, 2018 order, the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered Georgia Power to file supplemental information by April 5, 2016 in supportalso approved $542 million of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following Georgia Power's filing under the order, the Staff will conduct a review of all costs incurred relatedduring the seventeenth VCM reporting period (January 1, 2017 to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
June 30, 2017). The Georgia PSC has approved thirteenseventeen VCM reports covering the periods through June 30, 2015,2017, including total construction capital costs incurred which through that date totaled $3.1of $4.4 billion. On February 26, 2016, Georgia Power filedexpects to file its fourteentheighteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power ison February 28, 2018 requesting approval of $160approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion.July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6$4.8 billion as of December 31, 2015.2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issuesmatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.costs.
The ultimate outcome of these matters cannot be determined at this time.
GulfOther Matters
As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down by 20% each year until completely phased out for qualified property placed in service after December 31, 2027. Further, the business interest deduction is limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforwards, and depreciation and amortization through December 31, 2021, and thereafter to 30% of taxable income excluding interest and NOL carryforwards.
Regulated utility businesses, including the majority of the operations of the traditional electric operating companies and the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of the consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $264 million, a $0.4 billion decrease in regulatory assets, and a $6.9 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities. Also, the OCI ending balance at December 31, 2017 includes $30 million of stranded excess deferred tax balances, which will be adjusted through retained earnings in subsequent periods.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and relevant state regulatory bodies. On January 31, 2018, SCS, on behalf of the traditional electric operating companies, filed with the FERC a reduction to the open access transmission tariff charge for 2018 to reflect the revised federal corporate income tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the traditional electric operating companies' and the natural gas distribution utilities' rate filings to reflect the impacts of the Tax Reform Legislation.
On February 9, 2018, the Bipartisan Budget Act of 2018 was signed into law. Included in the tax extenders portion of the law were provisions extending PTCs on advanced nuclear power facilities and ITCs on qualified fuel cells. A subsidiary of PowerSecure installed fuel cells in 2017 which are expected to qualify for approximately $80 million of ITCs; however, the impact of the related tax benefits would be substantially offset by additional required payments under the applicable purchase contracts. Should Southern Company have a NOL in 2018, all of these ITCs may not be fully realized in 2018. See Note 3 to the financial statements under "Nuclear Construction" for additional information on the PTCs relating to advanced nuclear power facilities.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $870 million for the 2017 tax year and approximately $290 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes – Net Operating Loss," respectively, for additional information. The ultimate outcome of these matters cannot be determined at this time.
Tax Credits
The Tax Reform Legislation retained the renewable energy incentives that were included in the PATH Act. The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits and the tax benefit related to basis differences.
Southern Power
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. Southern Power is pursuing the sale of a 33% equity interest in the newly-formed holding company owning these solar assets. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Retail BaseSouthern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In 2016, the SEC began conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with no recommended enforcement action.
Litigation
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain
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Southern Company and Subsidiary Companies 2017 Annual Report
other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Investments in Leveraged Leases
A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
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Southern Company and Subsidiary Companies 2017 Annual Report
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 86% of Southern Company's total operating revenues for 2017, are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper County Energy Facility Rate CaseRecovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. Mississippi Power recorded total pre-tax charges to income related
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge of $78 million associated with the Kemper Settlement Agreement.
In the aggregate, since the Kemper County energy facility project started, Mississippi Power has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 14 to the financial statements for additional information on the individual charges by quarter.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and no longer represents a critical accounting estimate.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on Southern Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, Southern Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
Southern Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, Southern Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, Southern Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost
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Southern Company and Subsidiary Companies 2017 Annual Report
component of net periodic pension and other postretirement benefit plan expense decreased by approximately $96 million in 2016.
The following table illustrates the sensitivity to changes in Southern Company's long-term assumptions with respect to the assumed discount rate, the assumed salaries, and the assumed long-term rate of return on plan assets:
|
| | | | | |
Change in Assumption | Increase/(Decrease) in Total Benefit Expense for 2018 | | Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2017 | | Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2017 |
| (in millions) |
25 basis point change in discount rate | $40/$(38) | | $504/$(476) | | $68/$(65) |
25 basis point change in salaries | $24/$(23) | | $119/$(115) | | $–/$– |
25 basis point change in long-term return on plan assets | $33/$(33) | | N/A | | N/A |
N/A – Not applicable
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Goodwill and Other Intangible Assets
The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.3 billion at December 31, 2017.
Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power's acquisitions, other intangible assets, net of amortization totaled approximately $873 million at December 31, 2017.
The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.
See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding Southern Company's goodwill and other intangible assets and Note 12 to the financial statements for additional information related to Southern Company's recent acquisitions and proposed dispositions.
Derivatives and Hedging Activities
Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.
Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative
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Southern Company and Subsidiary Companies 2017 Annual Report
instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:
the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the impact of Southern Company's nonperformance risk on its liabilities.
Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.
Contingent Obligations
Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. Southern Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect Southern Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.
Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
FINANCIAL CONDITION AND LIQUIDITY
Overview
Earnings in all periods presented were negatively affected by charges associated with the Kemper IGCC; however, Southern Company's financial condition remained stable at December 31, 2017.
The Southern Company system's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system's cash needs. For the three-year period from 2018 through 2020, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
Southern Company's investments in the qualified pension plans and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plans are anticipated during 2018. See "Contractual Obligations" herein and Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities in 2017 totaled $6.4 billion, an increase of $1.5 billion from 2016. The increase in net cash provided from operating activities was primarily due to increases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in 2016, partially offset by the timing of vendor payments. Net cash provided from operating activities in 2016 totaled $4.9 billion, a decrease of $1.4 billion from 2015. Significant changes in operating cash flow for 2016 as compared to 2015 included approximately $1.0 billion of voluntary contributions to the qualified pension plan in 2016 and a $1.2 billion increase in unutilized ITCs and PTCs.
Net cash used for investing activities in 2017, 2016, and 2015 totaled $7.2 billion, $20.0 billion, and $7.3 billion, respectively. The cash used for investing activities in 2017 was primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility. The cash used for investing activities in 2015 was primarily due to the traditional electric operating companies' gross property additions for installation of equipment at electric generating facilities to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Power's acquisitions of solar facilities, and purchases of nuclear fuel.
Net cash provided from financing activities totaled $1.0 billion in 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries' continuous construction programs, Southern Power's acquisitions, and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Net cash provided from financing activities totaled $1.7 billion in 2015 primarily due to issuances of long-term debt and common stock and an increase in short-term debt, partially offset by common stock dividend payments and redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes in 2017 included decreases of $7.3 billion and $0.8 billion in accumulated deferred income taxes and deferred charges related to income taxes, respectively, and an increase of $7.0 billion in deferred credits related to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
income taxes primarily resulting from the impacts of the Tax Reform Legislation; an increase of $1.4 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.8 billion write-down of the gasification portions of the Kemper County energy facility and payments of $1.7 billion received by Georgia Power under the Guarantee Settlement Agreement; an increase of $3.1 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $1.1 billion in total stockholder's equity primarily related to the Kemper County energy facility charges, partially offset by the issuance of additional shares of common stock. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" and "Financing Activities" herein and Note 3 to the financial statements under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.
At the end of 2017, the market price of Southern Company's common stock was $48.09 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book value ratio of 201%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016.
Southern Company's consolidated ratio of common equity to total capitalization plus short-term debt was 31.5% and 33.3% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of the Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from any potential sale of a 33% equity interest in a newly-formed holding company that owns substantially all of its solar assets, if completed. Southern Company Gas also plans to utilize the proceeds from the pending asset sales of two of its natural gas distribution utilities. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See FUTURE EARNINGS POTENTIAL – "General" herein for additional information.
In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of December 31, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company and certain of its subsidiaries file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
well as the securities registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system.
In addition, Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
As of December 31, 2017, Southern Company's current liabilities exceeded current assets by $3.5 billion, due to $3.9 billion of long-term debt that is due within one year (comprised of approximately $1.0 billion at the parent company, $0.9 billion at Georgia Power, $1.0 billion at Mississippi Power, $0.8 billion at Southern Power, and $0.2 billion at Southern Company Gas) and $2.4 billion of notes payable (comprised of approximately $0.6 billion at the parent company, $0.2 billion at Georgia Power, $0.1 billion at Southern Power, and $1.5 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At December 31, 2017, Southern Company and its subsidiaries had approximately $2.1 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2018 |
| 2019 |
| 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
Southern Company(a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Southern Company Consolidated | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In 2013,May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the Florida PSC votedmaturity dates from 2020 to approve2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a settlement agreementnew multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.
At December 31, 2017, Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas, had $200 million of gas facility revenue bonds outstanding. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. See FUTURE EARNINGS POTENTIAL – "General" herein and Note 6 to the financial statements under "Gas Facility Revenue Bonds" for additional information.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017: | | | | | | | | | |
Commercial paper | $ | 1,832 |
| | 1.8 | % | | $ | 2,117 |
| | 1.3 | % | | $ | 2,946 |
|
Short-term bank debt | 607 |
| | 2.3 | % | | 555 |
| | 2.1 | % | | 1,020 |
|
Total | $ | 2,439 |
| | 1.9 | % | | $ | 2,672 |
| | 1.5 | % | | |
December 31, 2016: | | | | | | | | | |
Commercial paper | $ | 1,909 |
| | 1.1 | % | | $ | 976 |
| | 0.8 | % | | $ | 1,970 |
|
Short-term bank debt | 123 |
| | 1.7 | % | | 176 |
| | 1.7 | % | | 500 |
|
Total | $ | 2,032 |
| | 1.1 | % | | $ | 1,152 |
| | 1.1 | % | | |
December 31, 2015: | | | | | | | | | |
Commercial paper | $ | 740 |
| | 0.7 | % | | $ | 842 |
| | 0.4 | % | | $ | 1,563 |
|
Short-term bank debt | 500 |
| | 1.4 | % | | 444 |
| | 1.1 | % | | 795 |
|
Total | $ | 1,240 |
| | 0.9 | % | | $ | 1,286 |
| | 0.5 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015. |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016 and 2015, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016. For the year ended December 31, 2015, the Project Credit Facilities had a maximum amount outstanding of $137 million and an average amount outstanding of $13 million at a weighted average interest rate of 2.0% and had total amounts outstanding of $137 million at a weighted average interest rate of 2.0% at December 31, 2015.
Furthermore, in connection with the acquisition of a solar facility in July 2016, a subsidiary of Southern Power Company assumed a $217 million construction loan, which was fully repaid in September 2016. During this period, the credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.2%.
The Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.
Financing Activities
During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| (in millions) |
Southern Company(b) | $ | 300 |
| | $ | 400 |
| | $ | — |
| | $ | — |
| | $ | 950 |
| | $ | 400 |
|
Alabama Power | 1,100 |
| | 525 |
| | — |
| | 36 |
| | — |
| | — |
|
Georgia Power | 1,350 |
| | 450 |
| | 65 |
| | 65 |
| | 370 |
| | 17 |
|
Gulf Power | 300 |
| | 85 |
| | — |
| | — |
| | 6 |
| | — |
|
Mississippi Power | — |
| | 35 |
| | — |
| | — |
| | 40 |
| | 962 |
|
Southern Power | 525 |
| | 500 |
| | — |
| | — |
| | 43 |
| | 18 |
|
Southern Company Gas(c) | 450 |
| | — |
| | — |
| | — |
| | 400 |
| | 22 |
|
Other | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
Elimination(d) | — |
| | — |
| | — |
| | — |
| | (40 | ) | | (602 | ) |
Southern Company Consolidated | $ | 4,025 |
| | $ | 1,995 |
| | $ | 65 |
| | $ | 101 |
| | $ | 1,769 |
| | $ | 832 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas. |
| |
(d) | Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements. |
Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR.
Also in June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077.
In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The majority of the proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock.
In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
Subsequent to December 31, 2017, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power also issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.
In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
At December 31, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 40 |
|
At BBB- and/or Baa3 | $ | 665 |
|
At BB+ and/or Ba1(*) | $ | 2,390 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets and would be likely to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
impact the cost at which they do so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.
On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
On March 30, 2017, Fitch Ratings, Inc. placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.
On January 19, 2018, Moody's revised its rating outlooks for Southern Company and Alabama Power from stable to negative.
While it is unclear how the credit rating agencies, the FERC, and relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Absent actions by Southern Company and its subsidiaries to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation.
Market Price Risk
The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 2017 have a notional amount of $3.7 billion and are intended to mitigate interest rate volatility related to existing fixed and floating rate obligations. The weighted average interest rate on $6.3 billion of long-term variable interest rate exposure at December 31, 2017 was 2.43%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $63 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies. Southern Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | 41 |
| | $ | (213 | ) |
Acquisitions | — |
| | (54 | ) |
Contracts realized or settled | (8 | ) | | 141 |
|
Current period changes(a) | (196 | ) | | 171 |
|
Contracts outstanding at the end of the period, assets (liabilities), net(b) | $ | (163 | ) | | $ | 45 |
|
| |
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
| |
(b) | Excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016. |
The net hedge volumes of energy-related derivative contracts were 621 million mmBtu and 500 million mmBtu for the years ended December 31, 2017 and 2016, respectively.
For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above or (below) market prices was approximately $0.15 per mmBtu as of December 31, 2017 and $(0.05) per mmBtu as of December 31, 2016. The majority of the natural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.
At December 31, 2017 and 2016, substantially all of the intervenorsSouthern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to Gulf Power's retail base rate case (Gulf Power Settlement Agreement). Under the termsapplicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the Gulf Power Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million annually effective January 2014fair value hierarchy, and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%)over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and range (9.25% – 11.25%); and (3)thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements |
| December 31, 2017 |
| Total Fair Value | | Maturity |
| | Year 1 | | Years 2&3 | | Years 4&5 |
| (in millions) |
Level 1 | $ | (148 | ) | | $ | (71 | ) | | $ | (59 | ) | | $ | (18 | ) |
Level 2 | (15 | ) | | (30 | ) | | 13 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (163 | ) | | $ | (101 | ) | | $ | (46 | ) | | $ | (16 | ) |
The Southern Company system is accruing a return similarexposed to AFUDC on certain transmission system upgrades placed into service after January 2014 until Gulf Power's next base rate adjustment date or January 1, 2017, whichever comes first.
The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis pointsmarket price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the 30-year treasury yield rate increasesSouthern Company system does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
With the exception of Southern Company Gas' subsidiary, Atlanta Gas Light, and the Southern Company Gas wholesale gas services business, the Southern Company system is not exposed to concentrations of credit risk. Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 natural gas marketers in Georgia responsible for the retail sale of natural gas to end-use customers in Georgia. For 2017, the four largest natural gas marketers based on customer count accounted for 19% of Southern Company Gas' adjusted operating margin. Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2017, Southern Company Gas' wholesale gas services business' top 20 counterparties represented approximately 48%, or $203 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year.
Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in the Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.
Capital Requirements and Contractual Obligations
The Southern Company system's construction program is currently estimated to total approximately $9.4 billion for 2018, $9.3 billion for 2019, $8.4 billion for 2020, $7.0 billion for 2021, and $6.9 billion for 2022. These amounts include expenditures of approximately $1.2 billion, $1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $1.3 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" herein for additional information.
The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be approximately $0.3 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.4 billion for 2018, 2019, 2020, 2021, and 2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at least 75 basis points above 3.7947%existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions.
In addition, the construction program includes the development and construction of new electric generating facilities with designs that have not been previously constructed, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development, construction, and operation of new facilities is subject to a consecutive six-month period.number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements under "Nuclear Construction" for information regarding additional factors that may impact construction expenditures.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Southern Company system provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, leases, unrecognized tax benefits, pipeline charges, storage capacity, gas supply, asset management agreements, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
The Southern Company system's contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 3,865 |
| | $ | 6,293 |
| | $ | 5,206 |
| | $ | 32,610 |
| | $ | 47,974 |
|
Interest | 1,782 |
| | 3,286 |
| | 2,793 |
| | 27,535 |
| | 35,396 |
|
Preferred stock dividends of subsidiaries(b) | 16 |
| | 33 |
| | 33 |
| | — |
| | 82 |
|
Financial derivative obligations(c) | 493 |
| | 198 |
| | 37 |
| | 5 |
| | 733 |
|
Operating leases(d) | 149 |
| | 232 |
| | 178 |
| | 968 |
| | 1,527 |
|
Capital leases(d) | 39 |
| | 43 |
| | 20 |
| | 232 |
| | 334 |
|
Unrecognized tax benefits(e) | 18 |
| | — |
| | — |
| | — |
| | 18 |
|
Pipeline charges, storage capacity, and gas supply(f) | 813 |
| | 968 |
| | 714 |
| | 2,294 |
| | 4,789 |
|
Asset management agreements(g) | 9 |
| | 6 |
| | — |
| | — |
| | 15 |
|
Purchase commitments — | | | | | | | | |
|
|
Capital(h) | 9,016 |
| | 16,905 |
| | 12,749 |
| | — |
| | 38,670 |
|
Fuel(i) | 3,156 |
| | 3,573 |
| | 1,927 |
| | 5,588 |
| | 14,244 |
|
Purchased power(j) | 424 |
| | 884 |
| | 886 |
| | 3,716 |
| | 5,910 |
|
Other(k) | 407 |
| | 713 |
| | 434 |
| | 2,745 |
| | 4,299 |
|
Trusts — | | | | | | | | |
|
|
Nuclear decommissioning(l) | 5 |
| | 11 |
| | 11 |
| | 94 |
| | 121 |
|
Pension and other postretirement benefit plans(m) | 137 |
| | 275 |
| | — |
| | — |
| | 412 |
|
Total | $ | 20,329 |
| | $ | 33,420 |
| | $ | 24,988 |
| | $ | 75,787 |
| | $ | 154,524 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Represents preferred stock of subsidiaries. Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | See Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and included in "Purchased power." |
| |
(e) | See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. |
| |
(f) | Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. |
| |
(g) | Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services. |
| |
(h) | The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information. |
| |
(i) | Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(j) | Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. |
| |
(k) | Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
| |
(l) | Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information. |
| |
(m) | The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
Southern Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
litigation related to the Kemper County energy facility;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the inherent risks involved in transporting and storing natural gas;
the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas and the potential sale of a 33% equity interest in substantially all of Southern Power's solar assets, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by Southern Company from time to time with the SEC.
Southern Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Retail electric revenues | $ | 15,330 |
| | $ | 15,234 |
| | $ | 14,987 |
|
Wholesale electric revenues | 2,426 |
| | 1,926 |
| | 1,798 |
|
Other electric revenues | 681 |
| | 698 |
| | 657 |
|
Natural gas revenues | 3,791 |
| | 1,596 |
| | — |
|
Other revenues | 803 |
| | 442 |
| | 47 |
|
Total operating revenues | 23,031 |
| | 19,896 |
| | 17,489 |
|
Operating Expenses: | | | | | |
Fuel | 4,400 |
| | 4,361 |
| | 4,750 |
|
Purchased power | 863 |
| | 750 |
| | 645 |
|
Cost of natural gas | 1,601 |
| | 613 |
| | — |
|
Cost of other sales | 513 |
| | 260 |
| | — |
|
Other operations and maintenance | 5,481 |
| | 5,240 |
| | 4,416 |
|
Depreciation and amortization | 3,010 |
| | 2,502 |
| | 2,034 |
|
Taxes other than income taxes | 1,250 |
| | 1,113 |
| | 997 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 20,480 |
| | 15,267 |
| | 13,207 |
|
Operating Income | 2,551 |
| | 4,629 |
| | 4,282 |
|
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 160 |
| | 202 |
| | 226 |
|
Earnings from equity method investments | 106 |
| | 59 |
| | — |
|
Interest expense, net of amounts capitalized | (1,694 | ) | | (1,317 | ) | | (840 | ) |
Other income (expense), net | (55 | ) | | (93 | ) | | (39 | ) |
Total other income and (expense) | (1,483 | ) | | (1,149 | ) | | (653 | ) |
Earnings Before Income Taxes | 1,068 |
| | 3,480 |
| | 3,629 |
|
Income taxes | 142 |
| | 951 |
| | 1,194 |
|
Consolidated Net Income | 926 |
| | 2,529 |
| | 2,435 |
|
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | 45 |
| | 54 |
|
Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Consolidated Net Income Attributable to Southern Company | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
|
Common Stock Data: | | | | | |
Earnings per share — | | | | | |
Basic | $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
|
Diluted | 0.84 |
| | 2.55 |
| | 2.59 |
|
Average number of shares of common stock outstanding — (in millions) | | | | | |
Basic | 1,000 |
| | 951 |
| | 910 |
|
Diluted | 1,008 |
| | 958 |
| | 914 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Consolidated Net Income | $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Other comprehensive income: | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $34, $(84), and $(8), respectively | 57 |
| | (136 | ) | | (13 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(37), $43, and $4, respectively | (60 | ) | | 69 |
| | 6 |
|
Pension and other postretirement benefit plans: | | | | | |
Benefit plan net gain (loss), net of tax of $6, $10, and $(1), respectively | 17 |
| | 13 |
| | (2 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $(6), $3, and $4, respectively | (23 | ) | | 4 |
| | 7 |
|
Total other comprehensive income (loss) | (9 | ) | | (50 | ) | | (2 | ) |
Less: | | | | | |
Dividends on preferred and preference stock of subsidiaries | 38 |
| | 45 |
| | 54 |
|
Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 833 |
| | $ | 2,398 |
| | $ | 2,365 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| | | (in millions) |
Operating Activities: | | | | | |
Consolidated net income | $ | 926 |
| | $ | 2,529 |
| | $ | 2,435 |
|
Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 3,457 |
| | 2,923 |
| | 2,395 |
|
Deferred income taxes | 166 |
| | (127 | ) | | 1,404 |
|
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Allowance for equity funds used during construction | (160 | ) | | (202 | ) | | (226 | ) |
Pension and postretirement funding | (2 | ) | | (1,029 | ) | | (7 | ) |
Settlement of asset retirement obligations | (177 | ) | | (171 | ) | | (37 | ) |
Stock based compensation expense | 109 |
| | 121 |
| | 99 |
|
Hedge settlements | 6 |
| | (233 | ) | | (17 | ) |
Estimated loss on Kemper IGCC | 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | (47 | ) | | (122 | ) | | (413 | ) |
Other, net | (109 | ) | | (99 | ) | | 49 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (199 | ) | | (544 | ) | | 243 |
|
-Fossil fuel for generation | 36 |
| | 178 |
| | 61 |
|
-Natural gas for sale | 36 |
| | (226 | ) | | — |
|
-Other current assets | (143 | ) | | (206 | ) | | (152 | ) |
-Accounts payable | (280 | ) | | 301 |
| | (353 | ) |
-Accrued taxes | (142 | ) | | 1,456 |
| | 352 |
|
-Retail fuel cost over recovery | (212 | ) | | (231 | ) | | 289 |
|
-Mirror CWIP | — |
| | — |
| | (271 | ) |
-Other current liabilities | (45 | ) | | 250 |
| | 58 |
|
Net cash provided from operating activities | 6,395 |
| | 4,894 |
| | 6,274 |
|
Investing Activities: | | | | | |
Business acquisitions, net of cash acquired | (1,070 | ) | | (10,689 | ) | | (1,719 | ) |
Property additions | (7,423 | ) | | (7,310 | ) | | (5,674 | ) |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | 1,682 |
| | — |
| | — |
|
Investment in restricted cash | (17 | ) | | (733 | ) | | (160 | ) |
Distribution of restricted cash | 34 |
| | 742 |
| | 154 |
|
Nuclear decommissioning trust fund purchases | (811 | ) | | (1,160 | ) | | (1,424 | ) |
Nuclear decommissioning trust fund sales | 805 |
| | 1,154 |
| | 1,418 |
|
Cost of removal, net of salvage | (313 | ) | | (245 | ) | | (167 | ) |
Change in construction payables, net | 259 |
| | (121 | ) | | 402 |
|
Investment in unconsolidated subsidiaries | (152 | ) | | (1,444 | ) | | — |
|
Payments pursuant to LTSAs | (227 | ) | | (134 | ) | | (197 | ) |
Other investing activities | 42 |
| | (108 | ) | | 87 |
|
Net cash used for investing activities | (7,191 | ) | | (20,048 | ) | | (7,280 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (401 | ) | | 1,228 |
| | 73 |
|
Proceeds — | | | | | |
Long-term debt | 5,858 |
| | 16,368 |
| | 7,029 |
|
Common stock | 793 |
| | 3,758 |
| | 256 |
|
Preferred stock | 250 |
| | — |
| | — |
|
Short-term borrowings | 1,259 |
| | — |
| | 755 |
|
Redemptions and repurchases — | | | | | |
Long-term debt | (2,930 | ) | | (3,145 | ) | | (3,604 | ) |
Common stock | — |
| | — |
| | (115 | ) |
Interest-bearing refundable deposits | — |
| | — |
| | (275 | ) |
Preferred and preference stock | (658 | ) | | — |
| | (412 | ) |
Short-term borrowings | (659 | ) | | (478 | ) | | (255 | ) |
Distributions to noncontrolling interests | (119 | ) | | (72 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Payment of common stock dividends | (2,300 | ) | | (2,104 | ) | | (1,959 | ) |
Other financing activities | (222 | ) | | (512 | ) | | (116 | ) |
Net cash provided from financing activities | 951 |
| | 15,725 |
| | 1,700 |
|
Net Change in Cash and Cash Equivalents | 155 |
| | 571 |
| | 694 |
|
Cash and Cash Equivalents at Beginning of Year | 1,975 |
| | 1,404 |
| | 710 |
|
Cash and Cash Equivalents at End of Year | $ | 2,130 |
| | $ | 1,975 |
| | $ | 1,404 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 2,130 |
| | $ | 1,975 |
|
Receivables — | | | |
Customer accounts receivable | 1,806 |
| | 1,583 |
|
Energy marketing receivable | 607 |
| | 623 |
|
Unbilled revenues | 810 |
| | 706 |
|
Under recovered fuel clause revenues | 171 |
| | — |
|
Income taxes receivable, current | 63 |
| | 544 |
|
Other accounts and notes receivable | 635 |
| | 377 |
|
Accumulated provision for uncollectible accounts | (44 | ) | | (43 | ) |
Materials and supplies | 1,438 |
| | 1,462 |
|
Fossil fuel for generation | 594 |
| | 689 |
|
Natural gas for sale | 595 |
| | 631 |
|
Prepaid expenses | 452 |
| | 364 |
|
Other regulatory assets, current | 604 |
| | 581 |
|
Other current assets | 211 |
| | 230 |
|
Total current assets | 10,072 |
| | 9,722 |
|
Property, Plant, and Equipment: | | | |
In service | 103,542 |
| | 98,416 |
|
Less: Accumulated depreciation | 31,457 |
| | 29,852 |
|
Plant in service, net of depreciation | 72,085 |
| | 68,564 |
|
Nuclear fuel, at amortized cost | 883 |
| | 905 |
|
Construction work in progress | 6,904 |
| | 8,977 |
|
Total property, plant, and equipment | 79,872 |
| | 78,446 |
|
Other Property and Investments: | | | |
Goodwill | 6,268 |
|
| 6,251 |
|
Equity investments in unconsolidated subsidiaries | 1,513 |
|
| 1,549 |
|
Other intangible assets, net of amortization of $186 and $62 at December 31, 2017 and December 31, 2016, respectively | 873 |
| | 970 |
|
Nuclear decommissioning trusts, at fair value | 1,832 |
| | 1,606 |
|
Leveraged leases | 775 |
| | 774 |
|
Miscellaneous property and investments | 249 |
| | 270 |
|
Total other property and investments | 11,510 |
| | 11,420 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 825 |
| | 1,629 |
|
Unamortized loss on reacquired debt | 206 |
| | 223 |
|
Other regulatory assets, deferred | 6,943 |
| | 6,851 |
|
Other deferred charges and assets | 1,577 |
| | 1,406 |
|
Total deferred charges and other assets | 9,551 |
| | 10,109 |
|
Total Assets | $ | 111,005 |
| | $ | 109,697 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 3,892 |
| | $ | 2,587 |
|
Notes payable | 2,439 |
| | 2,241 |
|
Energy marketing trade payables | 546 |
| | 597 |
|
Accounts payable | 2,530 |
| | 2,228 |
|
Customer deposits | 542 |
| | 558 |
|
Accrued taxes — | | | |
Accrued income taxes | 6 |
| | 193 |
|
Unrecognized tax benefits | 18 |
| | 385 |
|
Other accrued taxes | 613 |
| | 667 |
|
Accrued interest | 488 |
| | 518 |
|
Accrued compensation | 959 |
| | 915 |
|
Asset retirement obligations, current | 351 |
| | 378 |
|
Acquisitions payable | 5 |
| | 489 |
|
Other regulatory liabilities, current | 337 |
| | 236 |
|
Other current liabilities | 868 |
| | 925 |
|
Total current liabilities | 13,594 |
| | 12,917 |
|
Long-Term Debt (See accompanying statements) | 44,462 |
| | 42,629 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 6,842 |
| | 14,092 |
|
Deferred credits related to income taxes | 7,256 |
| | 219 |
|
Accumulated deferred ITCs | 2,267 |
| | 2,228 |
|
Employee benefit obligations | 2,256 |
| | 2,299 |
|
Asset retirement obligations, deferred | 4,473 |
| | 4,136 |
|
Accrued environmental remediation | 389 |
| | 397 |
|
Other cost of removal obligations | 2,684 |
| | 2,748 |
|
Other regulatory liabilities, deferred | 239 |
| | 258 |
|
Other deferred credits and liabilities | 691 |
| | 880 |
|
Total deferred credits and other liabilities | 27,097 |
| | 27,257 |
|
Total Liabilities | 85,153 |
| | 82,803 |
|
Redeemable Preferred Stock of Subsidiaries (See accompanying statements) | 324 |
| | 118 |
|
Redeemable Noncontrolling Interests (See accompanying statements) | — |
| | 164 |
|
Total Stockholders' Equity (See accompanying statements) | 25,528 |
| | 26,612 |
|
Total Liabilities and Stockholders' Equity | $ | 111,005 |
| | $ | 109,697 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| | | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | | (in millions) | | | (percent of total) |
Long-Term Debt: | | | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | | | $ | 206 |
| | $ | 206 |
| | | | |
Long-term senior notes and debt — | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | |
2017 | 1.30% to 7.20% | | — |
| | 2,019 |
| | | | |
2018 | 1.50% to 5.40% | | 2,402 |
| | 2,403 |
| | | | |
2019 | 1.85% to 5.55% | | 3,074 |
| | 3,076 |
| | | | |
2020 | 2.00% to 4.75% | | 2,273 |
| | 1,326 |
| | | | |
2021 | 2.35% to 9.10% | | 2,643 |
| | 2,655 |
| | | | |
2022 | 1.00% to 8.70% | | 2,016 |
| | 1,378 |
| | | | |
2023 through 2047 | 1.85% to 7.30% | | 22,142 |
| | 20,369 |
| | | | |
Variable rates (1.82% to 3.75% at 1/1/17) due 2017 | | | — |
| | 461 |
| | | | |
Variable rates (2.29% to 3.05% at 12/31/17) due 2018 | | | 1,420 |
| | 1,520 |
| | | | |
Variable rates (2.04% to 2.18% at 12/31/17) due 2020 | | | 825 |
| | — |
| | | | |
Variable rates (2.55% to 2.79% at 12/31/17) due 2021 | | | 25 |
| | 25 |
| | | | |
Variable rate (3.75% at 1/1/17) due 2032 to 2036 | | | — |
| | 15 |
| | | | |
Total long-term senior notes and debt | | | 36,820 |
| | 35,247 |
| | | | |
Other long-term debt — | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | |
Maturity | Interest Rates | | | | | | | | |
2019 | 4.55% | | 25 |
| | 25 |
| | | | |
2022 | 2.10% to 2.35% | | 90 |
| | 90 |
| | | | |
2023 through 2049 | 1.15% to 5.15% | | 1,379 |
| | 1,339 |
| | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | | | 40 |
| | 76 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | | | 65 |
| | 65 |
| | | | |
Variable rates (1.83% to 1.84% at 12/31/17) due 2022 | | | 17 |
| | 17 |
| | | | |
Variable rates (1.59% to 1.88% at 12/31/17) due 2024 to 2053 | | | 1,680 |
| | 1,721 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | | | 270 |
| | 270 |
| | | | |
FFB loans — | | | | | | | | | |
2.57% to 3.86% due 2020 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2021 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2022 | | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2023 to 2044 | | | 2,493 |
| | 2,493 |
| | | | |
First mortgage bonds — | | | | | | | | | |
4.70% due 2019 | | | 50 |
| | 50 |
| | | | |
2.66% to 6.58% due 2023 to 2057 | | | 975 |
| | 575 |
| | | | |
Gas facility revenue bonds — | | | | | | | | | |
Variable rate (1.71% at 12/31/17) due 2022 | | | 47 |
| | 47 |
| | | | |
Variable rate (1.71% at 12/31/17) due 2024 to 2033 | | | 154 |
| | 154 |
| | | | |
Junior subordinated notes (5.00% to 6.25%) due 2057 to 2077 | | | 3,570 |
| | 2,350 |
| | | | |
Total other long-term debt | | | 10,987 |
| | 9,404 |
| | | | |
Unamortized fair value adjustment of long-term debt | | | 525 |
| | 578 |
| | | | |
Capitalized lease obligations | | | 204 |
| | 136 |
| | | | |
Unamortized debt premium | | | 44 |
| | 52 |
| | | | |
Unamortized debt discount | | | (206 | ) | | (194 | ) | | | | |
Unamortized debt issuance expense | | | (226 | ) | | (213 | ) | | | | |
Total long-term debt (annual interest requirement — $1.8 billion) | | 48,354 |
| | 45,216 |
| | | | |
Less amount due within one year | | | 3,892 |
| | 2,587 |
| | | | |
Long-term debt excluding amount due within one year | | | 44,462 |
| | 42,629 |
| | 63.2 | % | | 61.3 | % |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF CAPITALIZATION (continued) At December 31, 2017 and 2016 Southern Company and Subsidiary Companies 2017 Annual Report | | | | | | | | |
| | | 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| | | (in millions) | | | (percent of total) |
Redeemable Preferred Stock of Subsidiaries: | | | | | | | | | |
Cumulative preferred stock | | | | | | | | | |
$100 par or stated value — 4.20% to 5.44% | | | | | | | | | |
Authorized — 20 million shares | | | | | | | | | |
Outstanding — 1 million shares | | | 324 |
| | 81 |
| | | | |
$1 par value — 5.83% | | | | | | | | | |
Authorized — 28 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares: $25 stated value | | | — |
| | 37 |
| | | | |
Total redeemable preferred stock of subsidiaries (annual dividend requirement — $16 million) | | | 324 |
| | 118 |
| | 0.5 |
| | 0.2 |
|
Redeemable Noncontrolling Interests | | | — |
| | 164 |
| | — |
| | 0.2 |
|
Common Stockholders' Equity: | | | | | | | | | |
Common stock, par value $5 per share — | | | 5,038 |
| | 4,952 |
| | | | |
Authorized — 1.5 billion shares | | | | | | | | | |
Issued — 2017: 1.0 billion shares | | | | | | | | | |
— 2016: 991 million shares | | | | | | | | | |
Treasury — 2017: 0.9 million shares | | | | | | | | | |
— 2016: 0.8 million shares | | | | | | | | | |
Paid-in capital | | | 10,469 |
| | 9,661 |
| | | | |
Treasury, at cost | | | (36 | ) | | (31 | ) | | | | |
Retained earnings | | | 8,885 |
| | 10,356 |
| | | | |
Accumulated other comprehensive loss | | | (189 | ) | | (180 | ) | | | | |
Total common stockholders' equity | | | 24,167 |
| | 24,758 |
| | 34.4 |
| | 35.6 |
|
Preferred and Preference Stock of Subsidiaries and Noncontrolling Interests: | | | | | | | | | |
Non-cumulative preferred stock | | | | | | | | | |
$25 par value — 6.00% to 6.13% | | | | | | | | | |
Authorized — 60 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | | | | | | | |
— 2016: 2 million shares | | | — |
| | 45 |
| | | | |
Non-cumulative preference stock | | | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | | | |
Authorized — 65 million shares | | | | | | | | | |
Outstanding — 2017: no shares | | | — |
| | 196 |
| | | | |
— 2016: 8 million shares | | | | | | | | | |
$100 par or stated value — 5.60% to 6.50% | | | | | | | | | |
Outstanding — 2017: no shares | | | — |
| | 368 |
| | | | |
— 2016: 4 million shares | | | | | | | | | |
Noncontrolling interests | | | 1,361 |
| | 1,245 |
| | | | |
Total preferred and preference stock of subsidiaries and noncontrolling interests | | | 1,361 |
| | 1,854 |
| | 1.9 |
| | 2.7 |
|
Total stockholders' equity | | | 25,528 |
| | 26,612 |
| | | | |
Total Capitalization | | | $ | 70,314 |
| | $ | 69,523 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern Company Common Stockholders' Equity | | | | | |
| Number of Common Shares | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Preferred and Preference Stock of Subsidiaries | | Noncontrolling Interests | |
| Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings | | | | Total |
| (in thousands) | | (in millions) |
Balance at December 31, 2014 | 908,502 |
| | (725 | ) | | $ | 4,539 |
| | $ | 5,955 |
| | $ | (26 | ) | | $ | 9,609 |
| | $ | (128 | ) | | $ | 756 |
| | $ | 221 |
| $ | 20,926 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 2,367 |
| | — |
| | — |
| | — |
| 2,367 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| (2 | ) |
Stock issued | 6,571 |
| | (2,599 | ) | | 33 |
| | 223 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 256 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 100 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 100 |
|
Stock repurchased, at cost | — |
| | — |
| | — |
| | — |
| | (115 | ) | | — |
| | — |
| | — |
| | — |
| (115 | ) |
Cash dividends of $2.1525 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (1,959 | ) | | — |
| | — |
| | — |
| (1,959 | ) |
Preference stock redemption | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (150 | ) | | — |
| (150 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | (18 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| 12 |
|
Other | — |
| | (28 | ) | | — |
| | 4 |
| | (1 | ) | | (7 | ) | | — |
| | 3 |
| | (1 | ) | (2 | ) |
Balance at December 31, 2015 | 915,073 |
| | (3,352 | ) | | 4,572 |
| | 6,282 |
| | (142 | ) | | 10,010 |
| | (130 | ) | | 609 |
| | 781 |
| 21,982 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 2,448 |
| | — |
| | — |
| | — |
| 2,448 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (50 | ) | | — |
| | — |
| (50 | ) |
Stock issued | 76,140 |
| | 2,599 |
| | 380 |
| | 3,263 |
| | 115 |
| | — |
| | — |
| | — |
| | — |
| 3,758 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 120 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 120 |
|
Cash dividends of $2.2225 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (2,104 | ) | | — |
| | — |
| | — |
| (2,104 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| 32 |
|
Other | — |
| | (66 | ) | | — |
| | (4 | ) | | (4 | ) | | 2 |
| | — |
| | — |
| | — |
| (6 | ) |
Balance at December 31, 2016 | 991,213 |
| | (819 | ) | | 4,952 |
| | 9,661 |
| | (31 | ) | | 10,356 |
| | (180 | ) | | 609 |
| | 1,245 |
| 26,612 |
|
Consolidated net income attributable to Southern Company | — |
| | — |
| | — |
| | — |
| | — |
| | 842 |
| | — |
| | — |
| | — |
| 842 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (9 | ) | | — |
| | — |
| (9 | ) |
Stock issued | 17,319 |
| | — |
| | 86 |
| | 707 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 793 |
|
Stock-based compensation | — |
| | — |
| | — |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 105 |
|
Cash dividends of $2.3000 per share | — |
| | — |
| | — |
| | — |
| | — |
| | (2,300 | ) | | — |
| | — |
| | — |
| (2,300 | ) |
Preferred and preference stock redemptions | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (609 | ) | | — |
| (609 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | (122 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| 114 |
|
Other | — |
| | (110 | ) | | — |
| | (4 | ) | | (5 | ) | | (13 | ) | | — |
| | — |
| | 1 |
| (21 | ) |
Balance at December 31, 2017 | 1,008,532 |
| | (929 | ) | | $ | 5,038 |
| | $ | 10,469 |
| | $ | (36 | ) | | $ | 8,885 |
| | $ | (189 | ) | | $ | — |
| | $ | 1,361 |
| $ | 25,528 |
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
|
| | |
Note | | Page |
1 | | |
2 | | |
3 | | |
4 | | |
5 | | |
6 | | |
7 | | |
8 | | |
9 | | |
10 | | |
11 | | |
12 | | |
13 | | |
14 | | |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The Southern Company (Southern Company or the Company) is the parent company of four traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, Settlement Agreementand Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the consolidated financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on Southern Company's results of operations, financial position, or cash flows.
In 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements.
Southern Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements. Southern Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. Southern Company applied the modified retrospective method of adoption effective January 1, 2018. Southern Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company will adopt the new standard effective January 1, 2019.
Southern Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, Southern Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers and PPAs where certain of Southern Company's subsidiaries are the lessee and to land and outdoor lighting where certain of Southern Company's subsidiaries are the lessor. The traditional electric operating companies are currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, Southern Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. Southern Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. Southern Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of Southern Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. Southern Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 15, 2019, with early adoption permitted. Southern Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. Southern Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Regulatory Assets and Liabilities
The traditional electric operating companies and natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 | | 2016 | | Note |
| (in millions) | | |
Retiree benefit plans | $ | 3,931 |
| | $ | 3,959 |
| | (a,n) |
Asset retirement obligations-asset | 1,133 |
| | 1,080 |
| | (b,n) |
Deferred income tax charges | 814 |
| | 1,590 |
| | (b,p) |
Environmental remediation-asset | 511 |
| | 491 |
| | (j,n) |
Property damage reserves-asset | 333 |
| | 206 |
| | (i) |
Under recovered regulatory clause revenues | 317 |
| | 273 |
| | (g) |
Remaining net book value of retired assets | 306 |
| | 351 |
| | (o) |
Loss on reacquired debt | 223 |
| | 243 |
| | (c) |
Vacation pay | 183 |
| | 182 |
| | (f,n) |
Long-term debt fair value adjustment | 138 |
| | 155 |
| | (d) |
Deferred PPA charges | 119 |
| | 141 |
| | (e,n) |
Kemper County energy facility | 88 |
| | 201 |
| | (h) |
Other regulatory assets | 511 |
| | 487 |
| | (k) |
Deferred income tax credits | (7,261 | ) | | (219 | ) | | (b,p) |
Other cost of removal obligations | (2,684 | ) | | (2,774 | ) | | (b) |
Over recovered regulatory clause revenues | (155 | ) | | (203 | ) | | (g) |
Property damage reserves-liability | (135 | ) | | (177 | ) | | (l) |
Other regulatory liabilities | (266 | ) | | (120 | ) | | (m) |
Total regulatory assets (liabilities), net | $ | (1,894 | ) | | $ | 5,866 |
| | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(b) | Asset retirement and other cost of removal obligations are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. |
| |
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. |
| |
(d) | Recovered over the remaining life of the original debt issuances, which range up to 21 years. For additional information see Note 12 under "Southern Company – Merger with Southern Company Gas." |
| |
(e) | Recovered over the life of the PPA for periods up to six years. |
| |
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs or other applicable regulatory agencies over periods generally not exceeding 10 years. |
| |
(h) | Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." |
| |
(i) | Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information. |
| |
(j) | Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. |
| |
(k) | Comprised of numerous immaterial components including nuclear outage, fuel-hedging losses, deferred income tax charges - Medicare subsidy, cancelled construction projects, building and generating plant leases, property tax, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSCs over periods generally not exceeding 50 years. |
| |
(l) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. |
| |
(m) | Comprised of numerous immaterial components including retiree benefit plans, fuel-hedging gains, AROs, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs or other applicable regulatory agencies generally over periods not exceeding 20 years. |
| |
(n) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(o) | Amortized as approved by the appropriate state PSCs over periods generally up to 48 years. |
| |
(p) | As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be determined by the appropriate state PSCs or other applicable regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional information. |
In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
are to be reflected in rates. See Note 3 under "Regulatory Matters – Alabama Power," " – Georgia Power," " – Gulf Power," and " – Southern Company Gas" and "Kemper County Energy Facility" for additional information.
Revenues
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates for the traditional electric operating companies and natural gas distribution utilities may include provisions to adjust billings for fluctuations in fuel and purchased gas costs, fuel hedging, the energy component of purchased power costs, and certain other costs. For the traditional electric operating companies, revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors.
The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months. Programs of this type include weather normalization adjustments, revenue normalization mechanisms, and revenue true-up adjustments and are referred to as alternative revenue programs.
Southern Company's electric utility subsidiaries and Southern Company Gas have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
Income and Other Taxes
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and Southern Company Gas are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Under current tax law, certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded to income tax expense based on KWH production.
Federal ITCs and record a regulatory asset thatPTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2017 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have a consolidated federal net operating loss (NOL) carryforward for the 2017 tax year along with various state NOL carryforwards, which would result in income tax benefits in the future, if utilized. See Note 5 under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss" for additional information.
Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Southern Company system's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Electric utilities: | | | |
Generation | $ | 51,279 |
| | $ | 48,836 |
|
Transmission | 11,562 |
| | 11,156 |
|
Distribution | 19,239 |
| | 18,418 |
|
General | 4,276 |
| | 4,629 |
|
Plant acquisition adjustment | 126 |
| | 126 |
|
Electric utility plant in service | 86,482 |
| | 83,165 |
|
Natural gas distribution utilities: | | | |
Transportation and distribution | 13,078 |
| | 11,996 |
|
Utility plant in service | 99,560 |
| | 95,161 |
|
Information technology equipment and software | 752 |
| | 544 |
|
Communications equipment | 456 |
| | 424 |
|
Storage facilities | 1,598 |
| | 1,463 |
|
Other | 1,176 |
| | 824 |
|
Total other plant in service | 3,982 |
| | 3,255 |
|
Total plant in service | $ | 103,542 |
| | $ | 98,416 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs. In accordance with their respective state PSC orders, Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle, which ranges from 18 to 24 months.
Assets acquired under a capital lease are included as an offsetin property, plant, and equipment and are further detailed in the table below:
|
| | | | | | | |
| Asset Balances at December 31, |
| 2017 |
| 2016 |
| (in millions) |
Office buildings | $ | 216 |
|
| $ | 61 |
|
Nitrogen plant(*) | — |
|
| 83 |
|
Computer-related equipment | 51 |
|
| 63 |
|
Gas pipeline | 6 |
|
| 6 |
|
Less: Accumulated amortization | (72 | ) |
| (69 | ) |
Balance, net of amortization | $ | 201 |
|
| $ | 144 |
|
| |
(*) | Represents a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which was terminated following the suspension of the gasifier portion of the project. See Note 6 under "Capital Leases" for additional information. |
The amount of non-cash property additions recognized for the years ended December 31, 2017, 2016, and 2015 was $985 million, $1.3 billion, and $844 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2017, 2016, and 2015 was $162 million, $18 million, and $13 million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2017 and 3.0% in each of 2016 and 2015. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and natural gas distribution utilities. Accumulated depreciation for utility plant in service totaled $30.8 billion and $29.3 billion at December 31, 2017 and 2016, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
Under the terms of the 2013 ARP, Georgia Power amortized approximately $14 million annually from 2014 through 2016 of its remaining regulatory liability related to other cost of removal obligations.
See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for information regarding depreciation and amortization adjustments related to the other cost of removal regulatory liability.
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from two to 65 years. Accumulated depreciation for other plant in service totaled $673 million and $550 million at December 31, 2017 and 2016, respectively.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability and amounts to be recovered are reflected in the balance sheet as a regulatory asset.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has retirement obligations related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain electric transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded as the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of the AROs included in the balance sheets are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Balance at beginning of year | $ | 4,514 |
| | $ | 3,759 |
|
Liabilities incurred | 16 |
| | 66 |
|
Liabilities settled | (177 | ) | | (171 | ) |
Accretion | 179 |
| | 162 |
|
Cash flow revisions | 292 |
| | 698 |
|
Balance at end of year | $ | 4,824 |
| | $ | 4,514 |
|
In 2017 and 2016, the increases in cash flow revisions are primarily related to changes in closure strategy for ash ponds, landfills, and gypsum cells and the increases in liabilities settled are primarily related to ash pond closure activity.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the traditional electric operating companies will continue to periodically update these cost estimates as necessary.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an aggregateoverall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2017 and 2016, approximately $76 million and $56 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $77 million and $58 million at December 31, 2017 and 2016, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
At December 31, 2017, investment securities in the Funds totaled $1.8 billion, consisting of equity securities of $1.1 billion, debt securities of $725 million, and $47 million of other securities. At December 31, 2016, investment securities in the Funds totaled $1.6 billion, consisting of equity securities of $878 million, debt securities of $685 million, and $41 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the securities lending program.
Sales of the securities held in the Funds resulted in cash proceeds of $0.8 billion, $1.2 billion, and $1.4 billion in 2017, 2016, and 2015, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $233 million, which included $181 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $114 million, which included $48 million related to unrealized losses on securities held in the Funds at
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $11 million, which included $83 million related to unrealized gains and losses on securities held in the Funds at December 31, 2015. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
For Alabama Power, approximately $18 million and $19 million at December 31, 2017 and 2016, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, 2017 and 2016, the accumulated provisions for the external decommissioning trust funds were as follows:
|
| | | | | | | |
| External Trust Funds |
| 2017 | | 2016 |
| (in millions) |
Plant Farley | $ | 902 |
| | $ | 790 |
|
Plant Hatch | 583 |
| | 511 |
|
Plant Vogtle Units 1 and 2 | 346 |
| | 303 |
|
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2017 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2015 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2:
|
| | | | | | | | | | | |
| Plant Farley | | Plant Hatch | | Plant Vogtle Units 1 and 2 |
Decommissioning periods: | | | | | |
Beginning year | 2037 |
| | 2034 |
| | 2047 |
|
Completion year | 2076 |
| | 2075 |
| | 2079 |
|
| (in millions) |
Site study costs: | | | | | |
Radiated structures | $ | 1,362 |
| | $ | 678 |
| | $ | 568 |
|
Spent fuel management | — |
| | 160 |
| | 147 |
|
Non-radiated structures | 80 |
| | 64 |
| | 89 |
|
Total site study costs | $ | 1,442 |
| | $ | 902 |
| | $ | 804 |
|
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs in Georgia Power's 2019 base rate case. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Allowance for Funds Used During Construction and Interest Capitalized
The traditional electric operating companies and certain of the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional electric operating companies' and natural gas distribution utilities' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes, as a percentage of net income, was 25.5%, 11.4%, and 12.8% for 2017, 2016, and 2015, respectively.
Cash payments for interest totaled $1.7 billion, $1.1 billion, and $809 million in 2017, 2016, and 2015, respectively, net of amounts capitalized of $89 million, $125 million, and $124 million, respectively.
Impairment of Long-Lived Assets
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See "Leveraged Leases" herein and Note 3 under "Other Matters" and "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
Goodwill and Other Intangible Assets and Liabilities
Southern Company's goodwill and other intangible assets and liabilities primarily relate to Southern Company's 2016 acquisitions of PowerSecure and Southern Company Gas. See Note 12 under "Southern Company – Acquisition of PowerSecure" and " – Merger with Southern Company Gas" for additional information. Also see Note 12 under "Southern Power" for additional information regarding other intangible assets related to Southern Power's PPA fair value adjustments.
At December 31, 2017 and 2016, goodwill was $6.3 billion. Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company evaluated its goodwill in the fourth quarter 2017 and determined that no impairment was required.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, other intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| | At December 31, 2017 | | At December 31, 2016 |
| Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | (in millions) | | (in millions) |
Other intangible assets subject to amortization: | | | | | | | | |
Customer relationships | 11-26 years | $ | 288 |
| $ | (83 | ) | $ | 205 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
Trade names | 5-28 years | 159 |
| (17 | ) | 142 |
| | 158 |
| (5 | ) | 153 |
|
Storage and transportation contracts | 1-5 years | 64 |
| (34 | ) | 30 |
| | 64 |
| (2 | ) | 62 |
|
PPA fair value adjustments | 10-20 years | 456 |
| (47 | ) | 409 |
| | 456 |
| (22 | ) | 434 |
|
Other | 1-12 years | 17 |
| (5 | ) | 12 |
| | 11 |
| (1 | ) | 10 |
|
Total other intangible assets subject to amortization | | $ | 984 |
| $ | (186 | ) | $ | 798 |
|
| $ | 957 |
| $ | (62 | ) | $ | 895 |
|
Other intangible assets not subject to amortization: | | | | | | | | |
Federal Communications Commission licenses | | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
Total other intangible assets | | $ | 1,059 |
| $ | (186 | ) | $ | 873 |
|
| $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
Amortization associated with other intangible assets in 2017, 2016, and 2015 totaled $124 million, $50 million, and $3 million, respectively.
As of December 31, 2017, the estimated amortization associated with other intangible assets for the next five years is as follows:
|
| | | |
| Amortization |
| (in millions) |
2018 | $ | 95 |
|
2019 | 77 |
|
2020 | 65 |
|
2021 | 56 |
|
2022 | 51 |
|
Included in other deferred credits and liabilities on the balance sheet is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at Southern Company Gas. At December 31, 2017, the accumulated amortization of these intangible liabilities was $50 million. The remaining estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows: |
| | | |
| Amortization |
| (in millions) |
2018 | $ | 24 |
|
2019 | 17 |
|
Storm Damage Reserves
Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional electric operating companies accrued $41 million in 2017 and $40 million in each of 2016 and 2015. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2017, 2016, and 2015, there were no such additional accruals. See Note 3 under "Regulatory Matters – Alabama Power – Rate NDR" and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
"Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively.
Leveraged Leases
A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In the last six months of 2017, the financial and operational performance of one of the lessees and the associated generation assets has raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments to the Southern Holdings subsidiary beginning in June 2018. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If the June 2018 (or any future) lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable which had a balance of approximately $86 million as of December 31, 2017. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of December 31, 2017. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments, including the lease payment due in June 2018. The ultimate outcome of this matter cannot be determined at this time.
Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Net rentals receivable | $ | 1,498 |
| | $ | 1,481 |
|
Unearned income | (723 | ) | | (707 | ) |
Investment in leveraged leases | 775 |
| | 774 |
|
Deferred taxes from leveraged leases | (252 | ) | | (309 | ) |
Net investment in leveraged leases | $ | 523 |
| | $ | 465 |
|
A summary of the components of income from the leveraged leases follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Pretax leveraged lease income | $ | 25 |
| | $ | 25 |
| | $ | 20 |
|
Net impact of Tax Reform Legislation | 48 |
| | — |
| | — |
|
Income tax expense | (9 | ) | | (9 | ) | | (7 | ) |
Net leveraged lease income | $ | 64 |
| | $ | 16 |
| | $ | 13 |
|
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances of the electric utilities. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional electric operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Natural Gas for Sale
The natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's net income.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.
Financial Instruments
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.
The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2017, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial.
Southern Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | | | |
| Qualifying Hedges | | Pension and Other Postretirement Benefit Plans | | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | (115 | ) | | $ | (65 | ) | | $ | (180 | ) |
Current period change | (4 | ) | | (5 | ) | | (9 | ) |
Balance at December 31, 2017 | $ | (119 | ) | | $ | (70 | ) | | $ | (189 | ) |
2. RETIREMENT BENEFITS
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas and PowerSecure. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. This qualified pension plan is funded in accordance with requirements of ERISA. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2018. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2017 | | 2016 | | 2015 |
Pension plans | | | | | |
Discount rate – benefit obligations | 4.40 | % | | 4.58 | % | | 4.17 | % |
Discount rate – interest costs | 3.77 |
| | 3.88 |
| | 4.17 |
|
Discount rate – service costs | 4.81 |
| | 4.98 |
| | 4.48 |
|
Expected long-term return on plan assets | 7.92 |
| | 8.16 |
| | 8.20 |
|
Annual salary increase | 4.37 |
| | 4.37 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – benefit obligations | 4.23 | % | | 4.38 | % | | 4.04 | % |
Discount rate – interest costs | 3.54 |
| | 3.66 |
| | 4.04 |
|
Discount rate – service costs | 4.64 |
| | 4.85 |
| | 4.39 |
|
Expected long-term return on plan assets | 6.84 |
| | 6.66 |
| | 6.97 |
|
Annual salary increase | 4.37 |
| | 4.37 |
| | 3.59 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 |
| 2016 |
Pension plans |
|
|
|
Discount rate | 3.80 | % |
| 4.40 | % |
Annual salary increase | 4.32 |
|
| 4.37 |
|
Other postretirement benefit plans |
|
|
|
Discount rate | 3.68 | % |
| 4.23 | % |
Annual salary increase | 4.32 |
|
| 4.37 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of eight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
|
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 132 |
| | $ | 113 |
|
Service and interest costs | 4 |
| | 3 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Pension Plans
The total accumulated benefit obligation for the pension plans was $12.6 billion at December 31, 2017 and $11.3 billion at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 12,385 |
| | $ | 10,542 |
|
Acquisitions | — |
| | 1,244 |
|
Service cost | 293 |
| | 262 |
|
Interest cost | 455 |
| | 422 |
|
Benefits paid | (596 | ) | | (466 | ) |
Plan amendments | (26 | ) | | 39 |
|
Actuarial (gain) loss | 1,297 |
| | 342 |
|
Balance at end of year | 13,808 |
| | 12,385 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 11,583 |
| | 9,234 |
|
Acquisitions | — |
| | 837 |
|
Actual return (loss) on plan assets | 1,953 |
| | 902 |
|
Employer contributions | 52 |
| | 1,076 |
|
Benefits paid | (596 | ) | | (466 | ) |
Fair value of plan assets at end of year | 12,992 |
| | 11,583 |
|
Accrued liability | $ | (816 | ) | | $ | (802 | ) |
At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $13.2 billion and $652 million, respectively. All pension plan assets are related to the qualified pension plans.
Amounts presented in the following tables exclude regulatory assets of $334 million associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 3,273 |
| | $ | 3,207 |
|
Other current liabilities | (53 | ) | | (53 | ) |
Employee benefit obligations | (763 | ) | | (749 | ) |
Other regulatory liabilities, deferred | (118 | ) | | (87 | ) |
Accumulated OCI | 107 |
| | 100 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| Prior Service Cost | | Net (Gain) Loss |
| (in millions) |
Balance at December 31, 2017: | | | |
Accumulated OCI | $ | 3 |
| | $ | 104 |
|
Regulatory assets | 14 |
| | 3,140 |
|
Total | $ | 17 |
| | $ | 3,244 |
|
Balance at December 31, 2016: | | | |
Accumulated OCI | $ | 4 |
| | $ | 96 |
|
Regulatory assets | 51 |
| | 3,069 |
|
Total | $ | 55 |
| | $ | 3,165 |
|
Estimated amortization in net periodic pension cost in 2018: | | | |
Accumulated OCI | $ | 1 |
| | $ | 9 |
|
Regulatory assets | 4 |
| | 204 |
|
Total | $ | 5 |
| | $ | 213 |
|
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| Accumulated OCI | | Regulatory Assets |
| (in millions) |
Balance at December 31, 2015 | $ | 125 |
| | $ | 2,998 |
|
Net (gain) loss | (20 | ) | | 243 |
|
Change in prior service costs | 2 |
| | 37 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (13 | ) |
Amortization of net gain (loss) | (6 | ) | | (145 | ) |
Total reclassification adjustments | (7 | ) | | (158 | ) |
Total change | (25 | ) | | 122 |
|
Balance at December 31, 2016 | $ | 100 |
| | $ | 3,120 |
|
Net (gain) loss | 15 |
| | 227 |
|
Change in prior service costs | — |
| | (26 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (11 | ) |
Amortization of net gain (loss) | (7 | ) | | (155 | ) |
Total reclassification adjustments | (8 | ) | | (166 | ) |
Total change | 7 |
| | 35 |
|
Balance at December 31, 2017 | $ | 107 |
| | $ | 3,155 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 293 |
| | $ | 262 |
| | $ | 257 |
|
Interest cost | 455 |
| | 422 |
| | 445 |
|
Expected return on plan assets | (897 | ) | | (782 | ) | | (724 | ) |
Recognized net (gain) loss | 162 |
| | 150 |
| | 215 |
|
Net amortization | 12 |
| | 14 |
| | 25 |
|
Net periodic pension cost | $ | 25 |
| | $ | 66 |
| | $ | 218 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 634 |
|
2019 | 637 |
|
2020 | 663 |
|
2021 | 681 |
|
2022 | 704 |
|
2023 to 2027 | 3,836 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 2,297 |
| | $ | 1,989 |
|
Acquisitions | — |
| | 338 |
|
Service cost | 24 |
| | 22 |
|
Interest cost | 79 |
| | 76 |
|
Benefits paid | (136 | ) | | (119 | ) |
Actuarial (gain) loss | 65 |
| | (16 | ) |
Plan amendments | 3 |
| | — |
|
Retiree drug subsidy | 7 |
| | 7 |
|
Balance at end of year | 2,339 |
| | 2,297 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 944 |
| | 833 |
|
Acquisitions | — |
| | 100 |
|
Actual return (loss) on plan assets | 154 |
| | 58 |
|
Employer contributions | 84 |
| | 65 |
|
Benefits paid | (129 | ) | | (112 | ) |
Fair value of plan assets at end of year | 1,053 |
| | 944 |
|
Accrued liability | $ | (1,286 | ) | | $ | (1,353 | ) |
Amounts presented in the following tables exclude regulatory assets of $77 million associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company on July 1, 2016.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 382 |
| | $ | 419 |
|
Other current liabilities | (5 | ) | | (4 | ) |
Employee benefit obligations | (1,281 | ) | | (1,349 | ) |
Other regulatory liabilities, deferred | (41 | ) | | (41 | ) |
Accumulated OCI | 4 |
| | 7 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| Prior Service Cost | | Net (Gain) Loss |
| (in millions) |
Balance at December 31, 2017: | | | |
Accumulated OCI | $ | — |
| | $ | 4 |
|
Net regulatory assets | 21 |
| | 320 |
|
Total | $ | 21 |
| | $ | 324 |
|
Balance at December 31, 2016: | | | |
Accumulated OCI | $ | — |
| | $ | 7 |
|
Net regulatory assets | 25 |
| | 353 |
|
Total | $ | 25 |
| | $ | 360 |
|
Estimated amortization as net periodic postretirement benefit cost in 2018: | | | |
Net regulatory assets | $ | 7 |
| | $ | 14 |
|
The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| Accumulated OCI | | Net Regulatory Assets (Liabilities) |
| (in millions) |
Balance at December 31, 2015 | $ | 8 |
| | $ | 411 |
|
Net (gain) loss | (1 | ) | | (13 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | (6 | ) |
Amortization of net gain (loss) | — |
| | (14 | ) |
Total reclassification adjustments | — |
| | (20 | ) |
Total change | (1 | ) | | (33 | ) |
Balance at December 31, 2016 | $ | 7 |
| | $ | 378 |
|
Net (gain) loss | (3 | ) | | (21 | ) |
Change in prior service costs | — |
| | 3 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | (6 | ) |
Amortization of net gain (loss) | — |
| | (13 | ) |
Total reclassification adjustments | — |
| | (19 | ) |
Total change | (3 | ) | | (37 | ) |
Balance at December 31, 2017 | $ | 4 |
| | $ | 341 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 24 |
| | $ | 22 |
| | $ | 23 |
|
Interest cost | 79 |
| | 76 |
| | 78 |
|
Expected return on plan assets | (66 | ) | | (60 | ) | | (58 | ) |
Net amortization | 20 |
| | 21 |
| | 21 |
|
Net periodic postretirement benefit cost | $ | 57 |
| | $ | 59 |
| | $ | 64 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2018 | $ | 144 |
| | $ | (7 | ) | | $ | 137 |
|
2019 | 148 |
| | (8 | ) | | 140 |
|
2020 | 151 |
| | (8 | ) | | 143 |
|
2021 | 154 |
| | (9 | ) | | 145 |
|
2022 | 156 |
| | (9 | ) | | 147 |
|
2023 to 2027 | 780 |
| | (48 | ) | | 732 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The investment strategy for plan assets related to the Company's qualified pension plans is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plans is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company plan employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Investment Strategies and Benefit Plan Asset Fair Values
A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:
|
| |
Description | Valuation Methodology |
● Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
● International equity: A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | Domestic and International equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices are valued as Level 2 when the underlying holdings are comprised of Level 1 or Level 2 equity securities. |
● Fixed income: A mix of domestic and international bonds. | Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. |
● Trust-owned life insurance (TOLI): Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. |
● Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature.
● Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
● Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities. |
The fair values, and actual allocations relative to the target allocations, of Southern Company's pension plan (excluding Southern Company Gas) as of December 31, 2017 and 2016 are presented below. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
These fair values exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 2,405 |
| $ | 1,159 |
| $ | — |
| $ | — |
| $ | 3,564 |
| 26 | % | 31 | % |
International equity(*) | 1,555 |
| 1,403 |
| — |
| — |
| 2,958 |
| 25 |
| 25 |
|
Fixed income: | | | | | | 23 |
| 24 |
|
U.S. Treasury, government, and agency bonds | — |
| 841 |
| — |
| — |
| 841 |
|
|
|
Mortgage- and asset-backed securities | — |
| 8 |
| — |
| — |
| 8 |
|
|
|
Corporate bonds | — |
| 1,201 |
| — |
| — |
| 1,201 |
|
|
|
Pooled funds | — |
| 650 |
| — |
| — |
| 650 |
|
|
|
Cash equivalents and other | 217 |
| 11 |
| — |
| — |
| 228 |
|
|
|
Real estate investments | 469 |
| — |
| — |
| 1,188 |
| 1,657 |
| 14 |
| 13 |
|
Special situations | — |
| — |
| — |
| 180 |
| 180 |
| 3 |
| 1 |
|
Private equity | — |
| — |
| — |
| 669 |
| 669 |
| 9 |
| 6 |
|
Total | $ | 4,646 |
| $ | 5,273 |
| $ | — |
| $ | 2,037 |
| $ | 11,956 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 2,010 |
| $ | 927 |
| $ | — |
| $ | — |
| $ | 2,937 |
| 26 | % | 29 | % |
International equity(*) | 1,231 |
| 1,110 |
| — |
| — |
| 2,341 |
| 25 |
| 22 |
|
Fixed income: | | | | | | 23 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 588 |
| — |
| — |
| 588 |
|
|
|
Mortgage- and asset-backed securities | — |
| 13 |
| — |
| — |
| 13 |
|
|
|
Corporate bonds | — |
| 991 |
| — |
| — |
| 991 |
|
|
|
Pooled funds | — |
| 524 |
| — |
| — |
| 524 |
|
|
|
Cash equivalents and other | 996 |
| 2 |
| — |
| — |
| 998 |
|
|
|
Real estate investments | 310 |
| — |
| — |
| 1,152 |
| 1,462 |
| 14 |
| 13 |
|
Special situations | — |
| — |
|
|
| 180 |
| 180 |
| 3 |
| 2 |
|
Private equity | — |
| — |
| — |
| 549 |
| 549 |
| 9 |
| 5 |
|
Total | $ | 4,547 |
| $ | 4,155 |
| $ | — |
| $ | 1,881 |
| $ | 10,583 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of Southern Company Gas' pension plan assets for the period ended December 31, 2017 and 2016 are presented below. The fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 155 |
| $ | 323 |
| $ | — |
| $ | — |
| $ | 478 |
|
International equity(*) | — |
| 166 |
| — |
| — |
| 166 |
|
Fixed income: | | | | | |
U.S. Treasury, government, and agency bonds | — |
| 85 |
| — |
| — |
| 85 |
|
Corporate bonds | — |
| 39 |
| — |
| — |
| 39 |
|
Cash equivalents and other | 84 |
| 25 |
| — |
| 48 |
| 157 |
|
Real estate investments | 3 |
| — |
| — |
| 16 |
| 19 |
|
Private equity | — |
| — |
| — |
| 1 |
| 1 |
|
Total | $ | 242 |
| $ | 638 |
| $ | — |
| $ | 65 |
| $ | 945 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 142 |
| $ | 343 |
| $ | — |
| $ | — |
| $ | 485 |
|
International equity(*) | — |
| 185 |
| — |
| — |
| 185 |
|
Fixed income: |
|
|
|
|
|
U.S. Treasury, government, and agency bonds | — |
| 85 |
| — |
| — |
| 85 |
|
Corporate bonds | — |
| 41 |
| — |
| — |
| 41 |
|
Pooled funds | — |
| 66 |
| — |
| — |
| 66 |
|
Cash equivalents and other | 12 |
| 5 |
| — |
| 83 |
| 100 |
|
Real estate investments | 4 |
| — |
| — |
| 15 |
| 19 |
|
Private equity | — |
| — |
| — |
| 2 |
| 2 |
|
Total | $ | 158 |
| $ | 725 |
| $ | — |
| $ | 100 |
| $ | 983 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The composition of Southern Company Gas' pension plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | |
Equity | | 53 | % | | 65 | % | | 69 | % |
Fixed Income | | 15 |
| | 19 |
| | 20 |
|
Cash | | 2 |
| | 6 |
| | 1 |
|
Other | | 30 |
| | 10 |
| | 10 |
|
Balance at end of period | | 100 | % | | 100 | % | | 100 | % |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The fair values of Southern Company's (excluding Southern Company Gas) other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 132 |
| $ | 35 |
| $ | — |
| $ | — |
| $ | 167 |
| 37 | % | 40 | % |
International equity(*) | 47 |
| 76 |
| — |
| — |
| 123 |
| 23 |
| 23 |
|
Fixed income: | | | | | | 30 |
| 29 |
|
U.S. Treasury, government, and agency bonds | — |
| 32 |
| — |
| — |
| 32 |
|
|
|
Corporate bonds | — |
| 37 |
| — |
| — |
| 37 |
|
|
|
Pooled funds | — |
| 55 |
| — |
| — |
| 55 |
|
|
|
Cash equivalents and other | 10 |
| — |
| — |
| — |
| 10 |
|
|
|
Trust-owned life insurance | — |
| 426 |
| — |
| — |
| 426 |
|
|
|
Real estate investments | 16 |
| — |
| — |
| 36 |
| 52 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 20 |
| 20 |
| 4 |
| 2 |
|
Total | $ | 205 |
| $ | 661 |
| $ | — |
| $ | 61 |
| $ | 927 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | | Target Allocation | Actual Allocation |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total |
| (in millions) | | |
Assets: | | | | | | | |
Domestic equity(*) | $ | 118 |
| $ | 28 |
| $ | — |
| $ | — |
| $ | 146 |
| 39 | % | 40 | % |
International equity(*) | 37 |
| 61 |
| — |
| — |
| 98 |
| 23 |
| 21 |
|
Fixed income: | | | | | | 29 |
| 31 |
|
U.S. Treasury, government, and agency bonds | — |
| 24 |
| — |
| — |
| 24 |
|
|
|
Corporate bonds | — |
| 30 |
| — |
| — |
| 30 |
|
|
|
Pooled funds | — |
| 49 |
| — |
| — |
| 49 |
|
|
|
Cash equivalents and other | 41 |
| — |
| — |
| — |
| 41 |
|
|
|
Trust-owned life insurance | — |
| 382 |
| — |
| — |
| 382 |
|
|
|
Real estate investments | 11 |
| — |
| — |
| 35 |
| 46 |
| 5 |
| 5 |
|
Special situations | — |
| — |
| — |
| 5 |
| 5 |
| 1 |
| 1 |
|
Private equity | — |
| — |
| — |
| 17 |
| 17 |
| 3 |
| 2 |
|
Total | $ | 207 |
| $ | 574 |
| $ | — |
| $ | 57 |
| $ | 838 |
| 100 | % | 100 | % |
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of Southern Company Gas' other postretirement benefit plan assets for the period ended December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investment sales, and payables related to pending investment purchases. Special situations (absolute return and hedge funds) investment assets are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2017: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 69 |
| $ | — |
| $ | — |
| $ | 72 |
|
International equity(*) | — |
| 22 |
| — |
| — |
| 22 |
|
Fixed income: | | | | |
|
|
Pooled funds | — |
| 24 |
| — |
| — |
| 24 |
|
Cash equivalents and other | 2 |
| — |
| — |
| 1 |
| 3 |
|
Total | $ | 5 |
| $ | 115 |
| $ | — |
| $ | 1 |
| $ | 121 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | |
| Fair Value Measurements Using | |
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | Total |
As of December 31, 2016: | (Level 1) | (Level 2) | (Level 3) | (NAV) |
| (in millions) |
Assets: | | | | | |
Domestic equity(*) | $ | 3 |
| $ | 58 |
| $ | — |
| $ | — |
| $ | 61 |
|
International equity(*) | — |
| 18 |
| — |
| — |
| 18 |
|
Fixed income: | | | | | |
Pooled funds | — |
| 23 |
| — |
| — |
| 23 |
|
Cash equivalents and other | 1 |
| — |
| — |
| 2 |
| 3 |
|
Total | $ | 4 |
| $ | 99 |
| $ | — |
| $ | 2 |
| $ | 105 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The composition of Southern Company Gas' other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Other postretirement benefit plan assets: | | | | | | |
Equity | | 72 | % | | 76 | % | | 74 | % |
Fixed Income | | 24 |
| | 20 |
| | 23 |
|
Cash | | 1 |
| | 2 |
| | 1 |
|
Other | | 3 |
| | 2 |
| | 2 |
|
Total | | 100 | % | | 100 | % | | 100 | % |
Employee Savings Plan
Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2017, 2016, and 2015 were $118 million, $105 million, and $92 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. On June 12, 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.
On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable. The traditional electric operating companies and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability as of December 31, 2017 and 2016 was $22 million and $17 million, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million and $44 million as of December 31, 2017 and 2016, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Southern Company Gas' environmental remediation liability as of December 31, 2017 and 2016 was $388 million and $426 million, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on Southern Company's financial statements.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
In 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in their spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, Georgia Power recovered approximately $18 million, based on its ownership interests, which was credited to accounts where the original costs were charged, and used to reduce rate base, fuel, and cost of service for the benefit of customers. Also in 2015, Alabama Power recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries back for the benefit of customers in accordance with direction from their respective PSC and, therefore, no material impact on Southern Company's net income is expected.
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
Market-Based Rate Authority
The traditional electric operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
Alabama Power
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, Alabama Power's retail return exceeded the allowed WCE range which resulted in Alabama Power establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, Alabama Power applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, Alabama Power's actual retail return was within the allowed WCE range. On December 1, 2017, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.
In conjunction with Rate RSE, Alabama Power has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, Alabama Power had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," Alabama Power utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Rate CNP Compliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the factors associated with Alabama Power's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, Alabama Power had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.
Rate ECR
Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur within the next two to four years. Alabama Power's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
At December 31, 2017, Alabama Power's under recovered fuel costs totaled $25 million, which is included in other regulatory assets, current. At December 31, 2016, Alabama Power had an over recovered fuel balance of $76 million, which was included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs.
Rate NDR
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.
Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements.
Georgia Power
Rate Plans
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.
In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million; (3) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.
Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.
Georgia Power's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other regulatory liabilities, current.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory asset for storm damage totaled approximately $260 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements.
At December 31, 2017 and December 31, 2016, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million and $206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively.
Gulf Power
Retail Base Rate Cases
In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million betweenfrom January 2014 andthrough June 2017. In any given month, such depreciation expense reduction maywas not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power's next base rate case or next depreciationFor 2014 and dismantlement study proceeding, whichever comes first. For 2015, and 2014, Gulf Power recognized reductions in depreciation expense of $8.4 million and $20.1 million, and $8.4 million, respectively.
Pursuant to the No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power may not requestincreased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
On February 7, 2018, Mississippi Power revised its annual projected Performance Evaluation Plan (PEP) filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its retaildistribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.
On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
The ultimate outcome of these matters cannot be effective until after June 2017, unless Gulf Power's actual retail ROE falls below the authorized ROE range.determined at this time.
Integrated Coal Gasification Combined CycleKemper IGCC County Energy Facility
Overview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC willCounty energy facility was designed to utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC willMWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC.County energy facility. The mine, operated by North American Coal Corporation, started
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
commercial operation in 2013. In connection with the Kemper IGCC,County energy facility construction, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.County energy facility. The certificated cost estimate of the Kemper IGCCCounty energy facility included in the 2012 MPSC CPCN Order was $2.4$2.4 billion,, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excludingapproximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and AFUDC related to the Kemper IGCC.certain general exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCCCounty energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCCCounty energy facility in service usingin August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas in August 2014price forecast had decreased significantly and currently expectsthe estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to placeissue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the remainderKemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC,County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.
Recoveryapproximately $5.95 billion of the costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and equipment,gasifier-related costs, and certain termination costs during the costsuspension period prior to conclusion of the CO2 pipeline facilities, AFUDC,Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and certain general exceptions, including change of law, force majeure,plant closure and beneficial capital (which exists whencontract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power demonstrates thathas begun efforts to dispose of or abandon the purposemine and effectgasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relativeapproximately $99.3 million for costs related to the original proposalKemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the CPCN) (Cost Cap Exceptions) remains subject to reviewrelated regulatory assets and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impactsliabilities of the Mississippi Supreme Court's (Court) decision),eight years and actual costs incurred as of December 31, 2015, are as follows:six years, respectively. The revenue requirement also
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
|
| | | | | | | | | | | |
Cost Category | 2010 Project Estimate(f) | | Current Cost Estimate(a) | | Actual Costs |
| (in billions) |
Plant Subject to Cost Cap(b)(g) | $ | 2.40 |
| | $ | 5.29 |
| | $ | 4.83 |
|
Lignite Mine and Equipment | 0.21 | | 0.23 | | 0.23 |
CO2 Pipeline Facilities | 0.14 | | 0.11 | | 0.11 |
AFUDC(c) | 0.17 | | 0.69 | | 0.59 |
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g) | — |
| | 0.01 | | 0.01 |
General Exceptions | 0.05 | | 0.10 | | 0.09 |
Deferred Costs(e)(g) | — |
| | 0.20 | | 0.17 |
Total Kemper IGCC | $ | 2.97 |
| | $ | 6.63 |
| | $ | 6.03 |
|
| |
(a)
| Amountsreflects a disallowance related to a portion of Mississippi Power's investment in the Current Cost Estimate reflect estimated costs through August 31, 2016. |
| |
(b) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information. |
| |
(c)
| Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. |
| |
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. |
| |
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. |
| |
(f)
| The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
|
| |
(g) | Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015. |
Of the total costs, including post-in-service costsKemper County energy facility requested for inclusion in rate base, which was recorded in the lignite mine, incurredfourth quarter 2017 as an additional charge to income of December 31, 2015, $3.47 billion was included in property, plant, and equipment (which isapproximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the DOE GrantsKemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and estimated probable losses of $2.41 billion), $2 million in other property and investments, $69 million in fossil fuel stock, $45 million in materials and supplies, $21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets in the balance sheet.
Mississippi Power does not intend to seek rateinclude no recovery for any costs related toassociated with the constructiongasifier portion of the Kemper IGCC that exceedCounty energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $365 million ($226 million after tax), $868 million ($536 million after tax), and $1.2 billion ($729 million after tax) in 2015, 2014, and 2013, respectively. The increases to the cost estimate in 2015 primarily reflect costs for the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service datecompliance filing with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses onThe Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Mississippi Power's analysis ofSettlement Agreement also requires (i) the time needed to complete the start-up and commissioning activitiesCPCN for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respectCounty energy facility to the Kemper IGCC may result from factors including, but not limitedbe modified to labor costslimit it to natural gas combined cycle operation and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.
Rate Recovery of Kemper IGCC Costs
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN.(ii) Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could befile a material adverse impact on the financial statements.
2013 MPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreementreserve margin plan with the Mississippi PSC that was intended to establishby August 2018.
As of December 31, 2017, the process for resolving matters regarding cost recovery related tobalances associated with the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC,County energy facility regulatory assets and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013liabilities were $114 million and 3% effective January 1, 2014, which collectively were designed to collect $156$26 million, annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below.
2015 Rate Caserespectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Court decision, on July 10,Rate Case
On December 3, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration byissued the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover Mississippi Power's costs associated withRate Order regarding the Kemper IGCCCounty energy facility assets that arewere commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, thecosts. The In-Service Asset Rate Order providesprovided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period.costs. The In-Service Asset Rate Order also includesincluded a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes
In connection with the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
With implementation of the new rate on December 17, 2015, the interim rates were terminated and Mississippi Power recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. Mississippi Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.
Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015 of $6.63 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Mississippi Power expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interimwholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortizationfees over periods for these regulatory assets varyranging from two years to 10 years as set forth inyears. On July 6, 2017, the In-Service Asset Rate Order. As of December 31, 2015,Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the balance associated with these regulatory assets was $120 million. Other regulatory assets associated withKemper County energy facility following the remainderJuly 2017 completion of the Kemper IGCC totaled $96 million as of December 31, 2015. The
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
amortization period for certain of these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.
The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of December 31, 2015, Mississippi Power recorded a related regulatory liability of approximately $2 million. See "2015 Rate Case" herein for additional information.assets.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will ownowns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCCCounty energy facility site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managingresponsible for the mining operations. The contract with Liberty Fuels is effectiveoperations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power currently providesprovided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power hasrecovery and entered into agreementsan agreement with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015,. Denbury has the right to terminate the contract at any time because Mississippi Power has been engageddid not place the Kemper IGCC in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the CO2 agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements is not expected to have a material impact on Southern Company's revenues. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts.service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided InterestLitigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to SMEPA
In 2010 andinclude, among other things, Southern Company as amended in 2012,a defendant. The individual plaintiff alleges that Mississippi Power and SMEPA entered into an agreement whereby SMEPA agreed to purchase a 15% undivided interest inSouthern Company violated the Kemper IGCC. On May 20, 2015, SMEPA notifiedMississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power that it was terminating the agreement. Mississippi Power had previously received a total of $275 million of deposits from SMEPA that were returned to SMEPA, with interest of approximately $26 million, on June 3, 2015, as a result of the termination byand Southern Company pursuantconcealed, falsely represented, and failed to its guarantee obligation. Subsequently, Mississippi Power issued a promissory note infully disclose important facts concerning the aggregate principal amount of approximately $301 million to Southern Company, which matures December 1, 2017.
The In-Service Asset Proposalcost and the related rates approved by the Mississippi PSC excluded any costs associated with the 15% undivided interest. Mississippi Power continues to evaluate its alternatives with respect to its investment and the related costs associated with the 15% undivided interest.
Bonus Depreciation
On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service over the next five years. The PATH Act allows for 50% bonus depreciation for 2015, 2016, and 2017; 40% bonus depreciation for 2018; and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result in approximately $3 million of positive cash flows related to the combined cycle and associated common facilities portionschedule of the Kemper IGCC forCounty energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the 2015 tax yearCircuit Court to appoint a receiver to oversee, operate, manage, and approximately $360 million forotherwise control all affairs relating to the 2016 tax year, which may not all be realized in 2016 dueKemper County energy facility; ask the Circuit Court to a projected NOL on the
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, income tax return,Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
Nuclear Construction
Project Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the remaindercavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the Kemper IGCC in service in 2016. See "Kemper IGCC Schedule and Cost Estimate" herein for additional information.cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time.time, but could have a significant impact on Southern Company's financial statements.
Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.
Section 174 Research and Experimental Deduction
Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See "Bonus Depreciation" herein and Note 5 under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC,Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Duke Energy Florida, Inc. for afacilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit at Intercession City, Florida. Subsequent to December 31, 2015, Georgia Power exercised its contractual option to sell its ownership interest to Duke Energy Florida, Inc. contingent on regulatory approvals.LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc.
At December 31, 20152017, Alabama Power's, Georgia Power's, Southern Power's, and Southern Power'sCompany Gas' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
| | Facility (Type) | Percent Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP | Percent Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP |
| | | (in millions) | | | (in millions) |
Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | % | | $ | 3,503 |
| | $ | 2,084 |
| | $ | 63 |
| 45.7 | % | | $ | 3,564 |
| | $ | 2,141 |
| | $ | 70 |
|
Plant Hatch (nuclear) | 50.1 |
| | 1,230 |
| | 568 |
| | 90 |
| 50.1 |
| | 1,321 |
| | 595 |
| | 87 |
|
Plant Miller (coal) Units 1 and 2 | 91.8 |
| | 1,518 |
| | 587 |
| | 63 |
| 91.8 |
| | 1,717 |
| | 619 |
| | 54 |
|
Plant Scherer (coal) Units 1 and 2 | 8.4 |
| | 260 |
| | 86 |
| | 1 |
| 8.4 |
| | 261 |
| | 93 |
| | 8 |
|
Plant Wansley (coal) | 53.5 |
| | 915 |
| | 290 |
| | 13 |
| 53.5 |
| | 1,053 |
| | 335 |
| | 72 |
|
Rocky Mountain (pumped storage) | 25.4 |
| | 181 |
| | 125 |
| | — |
| 25.4 |
| | 182 |
| | 132 |
| | — |
|
Intercession City (combustion turbine) | 33.3 |
| | 13 |
| | 4 |
| | — |
| |
Plant Stanton (combined cycle) Unit A | 65.0 |
| | 157 |
| | 53 |
| | — |
| 65.0 |
| | 155 |
| | 55 |
| | — |
|
Dalton Pipeline (natural gas pipeline) | | 50.0 |
| | 241 |
| | 2 |
| | 13 |
|
Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, thatwhich are currently under construction.construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under "Retail Regulatory Matters – Georgia Power – "Nuclear Construction"Construction" for additional information.
Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, and Intercession City, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.
II-97Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Federal — | | | | | | | | | | |
Current | $ | (177 | ) | | $ | 175 |
| | $ | 363 |
| $ | (62 | ) | | $ | 1,184 |
| | $ | (177 | ) |
Deferred | 1,266 |
| | 695 |
| | 386 |
| (6 | ) | | (342 | ) | | 1,266 |
|
| 1,089 |
| | 870 |
| | 749 |
| (68 | ) | | 842 |
| | 1,089 |
|
State — | | | | | | | | | | |
Current | (33 | ) | | 93 |
| | (10 | ) | 37 |
| | (108 | ) | | (33 | ) |
Deferred | 138 |
| | 14 |
| | 110 |
| 173 |
| | 217 |
| | 138 |
|
| 105 |
| | 107 |
| | 100 |
| 210 |
| | 109 |
| | 105 |
|
Total | $ | 1,194 |
| | $ | 977 |
| | $ | 849 |
| $ | 142 |
| | $ | 951 |
| | $ | 1,194 |
|
Net cash payments (refunds) for income taxes in 20152017, 20142016, and 20132015 were $(9)$(410) million, $272$(148) million, and $139$(9) million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Deferred tax liabilities — | | | | | | |
Accelerated depreciation | $ | 12,767 |
| | $ | 11,125 |
| $ | 10,267 |
| | $ | 15,392 |
|
Property basis differences | 1,543 |
| | 1,332 |
| 955 |
| | 2,708 |
|
Leveraged lease basis differences | 308 |
| | 299 |
| 251 |
| | 314 |
|
Employee benefit obligations | 579 |
| | 613 |
| 516 |
| | 737 |
|
Premium on reacquired debt | 95 |
| | 103 |
| 54 |
| | 89 |
|
Regulatory assets associated with employee benefit obligations | 1,378 |
| | 1,390 |
| 1,046 |
| | 1,584 |
|
Regulatory assets associated with AROs | 1,422 |
| | 871 |
| 1,225 |
| | 1,781 |
|
Other | 586 |
| | 523 |
| 697 |
| | 907 |
|
Total | 18,678 |
| | 16,256 |
| 15,011 |
| | 23,512 |
|
Deferred tax assets — | | | | | | |
Federal effect of state deferred taxes | 479 |
| | 430 |
| 326 |
| | 597 |
|
Employee benefit obligations | 1,720 |
| | 1,675 |
| 1,307 |
| | 1,868 |
|
Over recovered fuel clause | 104 |
| | — |
| — |
| | 66 |
|
Other property basis differences | 695 |
| | 453 |
| 446 |
| | 401 |
|
Deferred costs | 83 |
| | 86 |
| 69 |
| | 100 |
|
ITC carryforward | 742 |
| | 480 |
| 2,420 |
| | 1,974 |
|
Federal NOL carryforward | | 518 |
| | 1,084 |
|
Unbilled revenue | 111 |
| | 67 |
| 57 |
| | 92 |
|
Other comprehensive losses | 85 |
| | 89 |
| 84 |
| | 152 |
|
AROs | 1,422 |
| | 871 |
| 1,197 |
| | 1,732 |
|
Estimated Loss on Kemper IGCC | 451 |
| | 631 |
| 722 |
| | 484 |
|
Deferred state tax assets | 220 |
| | 117 |
| 328 |
| | 266 |
|
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | | 465 |
| | — |
|
Other | 246 |
| | 342 |
| 485 |
| | 679 |
|
Total | 6,358 |
| | 5,241 |
| 8,424 |
| | 9,495 |
|
Valuation allowance | (2 | ) | | (49 | ) | (149 | ) | | (23 | ) |
Total deferred tax assets | 6,356 |
| | 5,192 |
| |
Total deferred income taxes | | 6,736 |
| | 14,040 |
|
Portion included in accumulated deferred tax assets | | (106 | ) | | (52 | ) |
Accumulated deferred income taxes | $ | 12,322 |
| | $ | 11,064 |
| $ | 6,842 |
| | $ | 14,092 |
|
On November 20, 2015,The implementation of the FASB issued ASU 2015-17,which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from deferred income taxes, current of $506 million, with $488 million to non-currentTax Reform Legislation significantly reduced accumulated deferred income taxes, and $18 million to other deferred charges, as well as $2 million from accrued income taxes to non-current accumulated deferred income taxes in Southern Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information.
The application ofpartially offset by bonus depreciation provisions in current tax law hasthe Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014.
At December 31, 2015, Southern Company had subsidiaries with NOL carryforwards for the states of Georgia, Mississippi, New Mexico, and Florida totaling approximately $697 million, $3.0 billion, $133 million, and $115 million, respectively, which could result in net state income tax benefits of $27 million, $97 million, $5 million, and $4 million, respectively, if utilized. These NOLs expire between 2017 and 2035, but are expected to be fully utilized by 2029. During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a portion of the NOL carryforward over a four-year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits. During 2015, approximately $87 million in New Mexico
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
NOLs expired resulting in a $3.5 million net state income tax increase and a corresponding decrease in the valuation allowance, with no tax impact.tax-related regulatory liabilities.
At December 31, 2015,2017, the tax-related regulatory assets to be recovered from customers were $1.6 billion.$825 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.
At December 31, 2015,2017, the tax-related regulatory liabilities to be credited to customers were $187 million.$7.3 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and the natural gas distribution utilities are amortized over the life of the related property with such amortization normally applied as a credit to
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2017, $22 million in 2016, and $21 million in 2015, $22 million in 2014, and $16 million in 2013.2015. Southern Power's deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015, $11 million in 2014, and $6 million in 2013.2015. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million $74 million, and $158 million for the yearsyear ended December 31, 2015, 2014,2015. No cash was received related to these incentives in 2017 and 2013, respectively, which had a material impact on cash flows.2016. Furthermore, the tax basis of the asset is reduced by 50% of the creditsITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015, $48 million in 2014, and $31 million in 2013.2015. See "Unrecognized Tax Benefits" below for further information.
Tax Credit Carryforwards
At December 31, 2015,2017, Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $554 million$2.1 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2020. 2027. The PTC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling $188approximately $318 million, which will expire between 2020 and 2026,2027 but are expected to be fully utilized.
Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will begin expiring in 2037 but is expected to be fully utilized by 2022.2019. The ultimate outcome of this matter cannot be determined at this time.
At December 31, 2017, the state NOL carryforwards for Southern Company's subsidiaries were as follows:
|
| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Begins Expiring |
| (in millions) | |
Mississippi | $ | 2,890 |
| $ | 114 |
| 2032 |
Oklahoma | 986 |
| 47 |
| 2036 |
Georgia | 524 |
| 23 |
| 2019 |
New York | 229 |
| 13 |
| 2036 |
New York City | 209 |
| 15 |
| 2036 |
Florida | 304 |
| 13 |
| 2034 |
Other states | 465 |
| 24 |
| Various |
Total | $ | 5,607 |
| $ | 249 |
|
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | 1.9 |
| | 2.3 |
| | 2.5 |
| 12.5 |
| | 2.1 |
| | 1.9 |
|
Employee stock plans dividend deduction | (1.2 | ) | | (1.4 | ) | | (1.6 | ) | (4.1 | ) | | (1.2 | ) | | (1.2 | ) |
Non-deductible book depreciation | 1.2 |
| | 1.4 |
| | 1.5 |
| 3.1 |
| | 0.9 |
| | 1.2 |
|
AFUDC-Equity | (2.2 | ) | | (2.9 | ) | | (2.6 | ) | (2.6 | ) | | (2.0 | ) | | (2.2 | ) |
Non-deductible equity portion on Kemper IGCC write-off | | 15.7 |
| | — |
| | — |
|
ITC basis difference | (1.5 | ) | | (1.6 | ) | | (1.2 | ) | (1.7 | ) | | (5.0 | ) | | (1.5 | ) |
Federal PTCs | | (12.1 | ) | | (1.2 | ) | | — |
|
Amortization of ITC | | (4.2 | ) | | (0.9 | ) | | (0.5 | ) |
Tax Reform Legislation | | (25.6 | ) | | — |
| | — |
|
Other | (0.3 | ) | | (0.3 | ) | | (0.5 | ) | (2.7 | ) | | (0.4 | ) | | 0.2 |
|
Effective income tax rate | 32.9 | % | | 32.5 | % | | 33.1 | % | 13.3 | % | | 27.3 | % | | 32.9 | % |
Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction, and non-taxable AFUDC equity.equity, and federal income tax benefits from ITCs and PTCs. However, in 2017, the effective tax rate was primarily lower due to the remeasurement of deferred income taxes resulting from the Tax Reform Legislation.
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Unrecognized tax benefits at beginning of year | $ | 170 |
| | $ | 7 |
| | $ | 70 |
| $ | 484 |
| | $ | 433 |
| | $ | 170 |
|
Tax positions increase from current periods | 43 |
| | 64 |
| | 3 |
| 10 |
| | 45 |
| | 43 |
|
Tax positions increase from prior periods | 240 |
| | 102 |
| | — |
| 10 |
| | 21 |
| | 240 |
|
Tax positions decrease from prior periods | (20 | ) | | (3 | ) | | (66 | ) | (196 | ) | | (15 | ) | | (20 | ) |
Reductions due to settlements | | (290 | ) | | — |
| | — |
|
Balance at end of year | $ | 433 |
| | $ | 170 |
| | $ | 7 |
| $ | 18 |
| | $ | 484 |
| | $ | 433 |
|
II-100The tax positions increase from current and prior periods for 2017 and 2016 relate primarily to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as deductions for R&E expenditures associated with the Kemper County energy facility. The tax positions decrease from prior periods for 2017 and 2016, and the reductions due to settlements for 2017, relate primarily to the
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The tax positions increase from current periods and prior periods for 2015 and 2014 relate primarily to deductions forsettlement of R&E expenditures associated with the Kemper IGCC.County energy facility and federal income tax benefits from deferred ITCs. See Note 3 under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" and "Section"Section 174 Research and Experimental Deduction"Deduction" herein for more information. The tax positions decrease from prior periods for 2015 and 2014 relates to federal and state income tax credits. The tax positions decrease from prior periods for 2013 relate primarily to the Company's compliance with final U.S. Treasury regulations that resulted in a tax accounting method change for repairs.
The impact on Southern Company's effective tax rate, if recognized, is as follows:
| |
| 2015 |
| 2014 |
| 2013 | 2017 |
| 2016 |
| 2015 |
| (in millions) | (in millions) |
Tax positions impacting the effective tax rate | $ | 10 |
|
| $ | 10 |
|
| $ | 7 |
| $ | 18 |
|
| $ | 20 |
|
| $ | 10 |
|
Tax positions not impacting the effective tax rate | 423 |
|
| 160 |
|
| — |
| — |
|
| 464 |
|
| 423 |
|
Balance of unrecognized tax benefits | $ | 433 |
|
| $ | 170 |
|
| $ | 7 |
| $ | 18 |
|
| $ | 484 |
|
| $ | 433 |
|
The tax positions impacting the effective tax rate for 2015, 2014, and 2013 primarily relate to federalstate tax benefits and state income tax credits.charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility and Southern Company's estimate of the uncertainty related to the amount of those benefits. The tax positions not impacting the effective tax rate for 20152016 and 20142015 relate to deductions for R&E expenditures associated with the Kemper IGCC.County energy facility. See "Section"Section 174 Research and Experimental Deduction"Deduction" herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for unrecognizedall tax benefitspositions other than the Section 174 R&E deductions was immaterial for all years presented.
Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months.months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company reduced tax payments for 2015 and included in its 2013 and 2014 consolidated federal income tax returnshas reflected deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern CompanyCounty energy facility in its federal income tax calculations since 2013 and filed amended its 2008 through 2013 federal income tax returns for 2008 through 2013 to also include deductions for Kemper IGCC-related R&E expenditures.
The Kemper IGCC is based on first-of-a-kind technology, andsuch deductions. In December 2016, Southern Company believes thatand the IRS reached a significant portionproposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. As a result of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position,approval, Southern Company had relatedrecognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated with these R&E deductions of approximately $423 million and associated interest of $9 million as of December 31, 2015. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time.accrued interest.
6. FINANCING
Long-Term Debt Payable to an Affiliated TrustSecurities Due Within One Year
Alabama Power has formed a wholly-owned trust subsidiary for the purposeA summary of issuing preferred securities. The proceedsscheduled maturities of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million as ofsecurities due within one year at December 31 2015 and 2014, which constitute substantially all of the assets of this trust and are reflected in the balance sheetswas as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2015 and 2014, trust preferred securities of $200 million were outstanding.follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Senior notes | $ | 2,354 |
| | $ | 1,995 |
|
Other long-term debt | 1,420 |
| | 485 |
|
Revenue bonds(*) | 90 |
| | 76 |
|
Capitalized leases | 31 |
| | 32 |
|
Unamortized debt issuance expense/discount | (3 | ) | | (1 | ) |
Total | $ | 3,892 |
| | $ | 2,587 |
|
| |
(*) | Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Senior notes | $ | 1,810 |
| | $ | 2,375 |
|
Other long-term debt | 829 |
| | 775 |
|
Pollution control revenue bonds | 4 |
| | 152 |
|
Capitalized leases | 32 |
| | 31 |
|
Unamortized debt issuance expense | (1 | ) | | (4 | ) |
Total | $ | 2,674 |
| | $ | 3,329 |
|
Maturities through 20202022 applicable to total long-term debt are as follows: $2.7 billion in 2016; $2.4 billion in 2017; $1.7$3.9 billion in 2018; $1.2$3.2 billion in 2019; and $1.4$3.2 billion in 2020.2020; $3.1 billion in 2021; and $2.2 billion in 2022.
Bank Term Loans
Southern Company and certain of the traditional operating companiesits subsidiaries have entered into various floating rate bank term loan agreementsagreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for loans bearing interest based on one-month LIBOR. general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
At December 31, 20152017, Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400$450 million, $45 million, $250 million, $900 million, and $400$420 million, respectively, of which $1.23$1.5 billion are reflected in the statements of capitalization as long-term debt and $475$600 million are reflected in the balance sheet as notes payable. At December 31, 2014,2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $775$400 million,. $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable.
In September 2015,June 2017, Southern Company entered into a $400two $100 million aggregate principal amount 18-monthshort-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capitalLIBOR from April 2017 to October 2017 and other general corporate purposes.subsequently repaid the loan in May 2017.
In April 2015,June 2017, Mississippi Power entered into two short-term floating rate bank loans with a maturity dateprepaid $300 million of April 1, 2016, in an aggregatethe outstanding principal amount of $475 million, bearing interest basedunder its $1.2 billion unsecured term loan, which matures on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.March 30, 2018.
In August 2015,September 2017, Southern Power Company entered into a $400amended its $60 million aggregate principal amount 13-month floating rate bankterm loan bearing interest based on one-month LIBOR. The proceeds were used for working capitalto, among other things, increase the aggregate principal amount to $100 million and other general corporate purposes, including Southern Power's growth strategy and continuous construction program.extend the maturity date from September 2017 to October 2018.
The outstanding bank loans as of December 31, 20152017 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC.securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2015,2017, each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement (Loanthe Loan Guarantee Agreement)Agreement in February 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.
Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
(On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for Eligible Project Costs).Costs. Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46$3.46 billion.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion. of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.
All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
In February 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicableaddition to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which are being amortized over the life of the borrowings under the FFB Credit Facility.
In December 2014, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million. The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044.
In June and December 2015, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million and $400 million, respectively. The interest rate applicable to the $600 million principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072%, both for an interest period that extends to 2044.
Futureconditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
Upon satisfaction of all conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
At both December 31, 2017 and 2016, Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note,Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
Senior Notes
Southern Company and its subsidiaries issued a total of $3.7$4.0 billion of senior notes in 2015.2017. Southern Company issued $600 million$0.3 billion and its subsidiaries issued a total of $3.1$3.7 billion. The proceeds of theseSouthern Company's issuances were used to repay short-term indebtedness and for other general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs, and,programs. A portion of the proceeds of Gulf Power's senior note issuances was used to redeem all of Gulf Power's outstanding shares of preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for Southern Power, its growth strategy.additional information.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
At December 31, 20152017 and 20142016, Southern Company and its subsidiaries had a total of $19.1$35.1 billion and $18.2$33.0 billion, respectively, of senior notes outstanding. At December 31, 20152017 and 2014,2016, Southern Company had a total of $2.4$10.2 billion and $2.2$10.3 billion, respectively, of senior notes outstanding.
Subsequent to December 31, 2015, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes These amounts include senior notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of its Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes.within one year.
Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary.
Junior Subordinated Notes
At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion, respectively, of junior subordinated notes outstanding.
In October 2015,June 2017, Southern Company issued $1.0 billion$500 million aggregate principal amount of Series 2015A 6.25%2017A 5.325% Junior Subordinated Notes due October 15, 2075.June 21, 2057. The proceeds were used to pay a portion of Southern Company's outstandingrepay short-term indebtedness and for other general corporate purposes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of Georgia Power's preferred and preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of pollution controlrevenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion and $3.2 billion of outstanding pollution control revenue bondsbond obligations at December 31, 20152017 and December 31, 2014, respectively.2016, which includes pollution control revenue bonds classified as due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
Plant Daniel Revenue Bonds
In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets"Assets Subject to Lien"Lien" herein for additional information.
Gas Facility Revenue Bonds
Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
agencies or counties to investors, and proceeds from each issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million.
The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.
Other Revenue Bonds
Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCCCounty energy facility and related facilities.
Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 20152017 and 2014.2016. Such amounts are reflected in the statements of capitalization as other long-term seniordebt.
First Mortgage Bonds
Nicor Gas, a subsidiary of Southern Company Gas, had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016, respectively. These bonds have been issued with maturities ranging from 2019 to 2057. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See "Assets Subject to Lien" herein for additional information.
On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.
Long-Term Debt Payable to an Affiliated Trust
Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million outstanding as of December 31, 2017 and debt.2016, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2017 and 2016, trust preferred securities of $200 million were outstanding.
Capital Leases
Assets acquired under capital leases are recorded in the balance sheets as utilityproperty, plant, in serviceand equipment and the related obligations are classified as long-term debt.
In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC,County energy facility, which resulted in a capital lease obligation of $74 million at December 31, 20152016. Following the suspension of the Kemper IGCC, Mississippi Power entered into an asset purchase and 2014 of approximately $77 million and $80 million, respectively,settlement agreement in December 2017 with an annual interest rate of 4.9% for both years. Amortization ofthe lessor, which terminated the capital lease assetobligation. See Note 3 under "Kemper County Energy Facility" for the air separation unit will begin when the Kemper IGCC is placed in service.additional information.
At December 31, 20152017 and 2014,2016, the capitalized lease obligations for Georgia Power's corporate headquarters building were $35$22 million and $40$28 million, respectively, with an annual interest rate of 7.9% for both years.
At December 31, 2015 and 2014, Alabama Power had a capitalized lease obligation of $5 million for a natural gas pipeline with an annual interest rate of 6.9%.
At December 31, 20152017 and 20142016, a subsidiary of Southern Company had capital lease obligations of approximately $30$177 million and $34$29 million, respectively, for an office building and certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.2%1.5% to 3.1%4.7%.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Other Obligations
In 2012, January 2014, and October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. In 2013, Southern Company entered into an agreement with SMEPA under which Southern Company agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement between Mississippi Power and SMEPA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures on December 1, 2017.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2015.2017.
The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant"Plant Daniel Revenue Bonds"Bonds" herein for additional information.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
See "DOE"DOE Loan Guarantee Borrowings"Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.
EachThe first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See "First Mortgage Bonds" herein for additional information.
Under the terms of the Project Credit Facilities (defined below) is secured byPPA and the membership interestsexpansion PPA for Southern Power's Mankato project, which was acquired in 2016, approximately $442 million of assets, primarily related to property, plant, and assets of the subsidiary of Southern Power Company partyequipment, are subject to the agreement.lien at December 31, 2017. See Note 12 under "Southern Power" for additional information.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock solar facility in Pecos County, Texas. Roserock is in a litigation dispute with McCarthy Building Companies, Inc. (McCarthy) regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. Southern Power intends to vigorously pursue its claims against McCarthy and defend against McCarthy's claims, the ultimate outcome of which cannot be determined at this time.
Bank Credit Arrangements
At December 31, 20152017, committed credit arrangements with banks were as follows:
| | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2016 | | 2017 | | 2018 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2018 | | 2019 | | 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
Southern Company (a) | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 40 |
| | — |
| | 500 |
| | 800 |
| | 1,340 |
| | 1,340 |
| | — |
| | — |
| | — |
| | 40 |
| 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 80 |
| | 30 |
| | 165 |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 30 |
| 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 220 |
| | — |
| | — |
| | — |
| | 220 |
| | 195 |
| | 30 |
| | 15 |
| | 45 |
| | 175 |
| 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power (b) | — |
| | — |
| | — |
| | 600 |
| | 600 |
| | 566 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 70 |
| | — |
| | — |
| | — |
| | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | 70 |
| 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Total | $ | 410 |
| | $ | 30 |
| | $ | 1,665 |
| | $ | 4,400 |
| | $ | 6,505 |
| | $ | 6,428 |
| | $ | 80 |
| | $ | 15 |
| | $ | 95 |
| | $ | 315 |
| |
Southern Company Consolidated | | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | ExcludesRepresents the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.Southern Company parent entity. |
| |
(b) | ExcludesDoes not include Southern Power's $120 million continuing letter of credit agreements (Project Credit Facilities) assumed with the acquisitionfacility for standby letters of certain solar facilities, which are non-recourse to Southern Power Company, the proceedscredit expiring in 2019, of which are being used to finance project costs related to such solar facilities currently under construction. See Note 12 under "Southern Power"$19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for additional information.which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
As reflected in the table above, in August 2015, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended and restated their multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $1.25 billion from $1.0 billion and to $600 million from $500 million, respectively. Georgia Power increased its
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016. In September 2015,May 2017, Southern Company, entered into an additional multi-year credit arrangement for $1.0 billion with a maturity date of 2018. Alabama Power, entered into a new $500 million three-year credit arrangement which replaced a majority of Alabama Power's bilateral credit arrangements. In November 2015, GulfGeorgia Power, amended and restatedSouthern Power Company each amended certain of itstheir multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the majoritynew multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of Gulf Power's agreementsits multi-year credit arrangements to extend the maturity dates from 20162017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional electric operating companies, and Southern Power Company.Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levellevels to 70% of total capitalization, as defined in the agreements, and most of thesethe other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements and other hybrid securities, and, for Southern Company and Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC.securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2015,2017, Southern Company, the traditional electric operating companies, and Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants.
A portion of the $6.4$8.1 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies' pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs.programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 20152017 was approximately $1.8 billion.$1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2015,2017, the traditional electric operating companies had approximately $181$714 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 Subsequent to provide financing for the MergerDecember 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in the eventa long-term financing is not available. The Bridge Agreement provides for total loan commitmentsinterest rate mode were remarketed in an aggregate amount of $8.1 billion to fund the payment of the cash consideration payable under the Merger Agreement and other cash payments required in connection with the consummation of the Merger, the Bridge Agreement and the borrowings thereunder, the other financing transactions related to the Merger, and the payment of fees and expenses incurred in connection with the foregoing. If funded, the loan under the Bridge Agreement will mature and be payable in full on the date that is 364 days after the funding of the commitments under the Bridge Agreement. As of December 31, 2015, Southern Company had no outstanding loans under the Bridge Agreement. See Note 12 under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger.index rate mode.
Southern Company, the traditional electric operating companies and(other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks.above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Details of short-term borrowings were as follows:
| | | Short-term Debt at the End of the Period | Short-term Debt at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate | Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | | (in millions) | | |
December 31, 2015: | | | | |
December 31, 2017: | | | | |
Commercial paper | $ | 740 |
| | 0.7 | % | $ | 1,832 |
| | 1.8 | % |
Short-term bank debt | 500 |
| | 1.4 | % | 607 |
| | 2.3 | % |
Total | $ | 1,240 |
| | 0.9 | % | $ | 2,439 |
| | 1.9 | % |
December 31, 2014: | | | | |
December 31, 2016: | | | | |
Commercial paper | $ | 803 |
| | 0.3 | % | $ | 1,909 |
| | 1.1 | % |
Short-term bank debt | — |
| | — | % | 123 |
| | 1.7 | % |
Total | $ | 803 |
| | 0.3 | % | $ | 2,032 |
| | 1.1 | % |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017 and had total amounts outstanding as of December 31, 2015 of $137$209 million at a weighted average interest rate of 2.0%.2.1% at December 31, 2016.
Redeemable Preferred Stock of Subsidiaries
EachAt December 31, 2016, each of the traditional electric operating companies has issuedhad outstanding preferred and/or preference stock. During 2017, Alabama Power and Gulf Power each redeemed all of its outstanding preference stock and Georgia Power redeemed all of its outstanding preferred and preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power dodid not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "noncontrolling interests,"Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity.
At December 31, 2015,The following table presents changes during the outstandingyear in redeemable preferred stock of subsidiaries for Southern Company:
|
| | | |
| Redeemable Preferred Stock of Subsidiaries |
| (in millions) |
Balance at December 31, 2014 | $ | 375 |
|
Issued | — |
|
Redeemed | (262 | ) |
Issuance costs | 5 |
|
Balance at December 31, 2015: | 118 |
|
Issued | — |
|
Redeemed | — |
|
Balance at December 31, 2016: | 118 |
|
Issued | 250 |
|
Redeemed | (38 | ) |
Issuance costs | (6 | ) |
Balance at December 31, 2017: | $ | 324 |
|
NOTES (continued)
Southern Company was $118 million. At December 31, 2014 and 2013, the outstanding redeemable preferred stock of subsidiaries of Southern Company was $375 million.Subsidiary Companies 2017 Annual Report
In May 2015, Alabama Power redeemed 6.48 million shares ($162 million aggregate stated capital) of its 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date and 4.0 million shares ($100 million aggregate stated capital) of its 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date. Additionally, $5 million of issuance costs were transferred from redeemable preferred stock of subsidiaries to common stockholder's equity upon redemption.
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2015, 2014,2017, 2016, and 2013,2015, the traditional electric operating companies and Southern Power incurred fuel expense of $4.8$4.4 billion, $6.0$4.4 billion, and $5.5$4.8 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system's future fuel needs will continue to be purchased under long-term commitments.
In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $235 million, $232 million, and $227 million $198for 2017, 2016, and 2015, respectively.
Estimated total obligations under these commitments at December 31, 2017 were as follows:
|
| | | | | | | |
| Operating Leases | | Other |
| (in millions) |
2018 | $ | 247 |
| | $ | 7 |
|
2019 | 250 |
| | 6 |
|
2020 | 247 |
| | 4 |
|
2021 | 249 |
| | 5 |
|
2022 | 252 |
| | 4 |
|
2023 and thereafter | 806 |
| | 38 |
|
Total | $ | 2,051 |
| | $ | 64 |
|
Pipeline Charges, Storage Capacity, and Gas Supply
Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million, mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and $157valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.
Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:
|
| | | |
| Pipeline Charges, Storage Capacity, and Gas Supply |
| (in millions) |
2018 | $ | 813 |
|
2019 | 552 |
|
2020 | 416 |
|
2021 | 375 |
|
2022 | 339 |
|
2023 and thereafter | 2,294 |
|
Total | $ | 4,789 |
|
Operating Leases
The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $176 million, $169 million, and $130 million for 2017, 2016, and 2015, 2014,respectively. Southern Company includes any step rents, fixed escalations, and 2013, respectively.lease concessions in its computation of minimum lease payments.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Estimated total obligations under these commitments at December 31, 2015 were as follows:
|
| | | | | | | |
| Operating Leases (*) | | Other |
| (in millions) |
2016 | $ | 233 |
| | $ | 10 |
|
2017 | 242 |
| | 8 |
|
2018 | 246 |
| | 7 |
|
2019 | 249 |
| | 8 |
|
2020 | 246 |
| | 4 |
|
2021 and thereafter | 1,291 |
| | 47 |
|
Total | $ | 2,507 |
| | $ | 84 |
|
| |
(*) | A total of $304 million of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. |
Operating Leases
The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $130 million, $118 million, and $123 million for 2015, 2014, and 2013, respectively. Southern Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term.
As of December 31, 2015,2017, estimated minimum lease payments under operating leases were as follows:
| | | Minimum Lease Payments | Minimum Lease Payments |
| Barges & Railcars | | Other | | Total | Barges & Railcars | | Other(*) | | Total |
| (in millions) | (in millions) |
2016 | $ | 40 |
| | $ | 81 |
| | $ | 121 |
| |
2017 | 25 |
| | 78 |
| | 103 |
| |
2018 | 14 |
| | 67 |
| | 81 |
| $ | 21 |
| | $ | 128 |
| | $ | 149 |
|
2019 | 6 |
| | 55 |
| | 61 |
| 11 |
| | 113 |
| | 124 |
|
2020 | 6 |
| | 47 |
| | 53 |
| 9 |
| | 99 |
| | 108 |
|
2021 and thereafter | 16 |
| | 690 |
| | 706 |
| |
2021 | | 8 |
| | 87 |
| | 95 |
|
2022 | | 6 |
| | 77 |
| | 83 |
|
2023 and thereafter | | 5 |
| | 963 |
| | 968 |
|
Total | $ | 107 |
| | $ | 1,018 |
| | $ | 1,125 |
| $ | 60 |
| | $ | 1,467 |
| | $ | 1,527 |
|
| |
(*) | Includes operating leases for cellular tower space, facilities, vehicles, and other equipment. |
For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions.
In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $48$44 million. At the termination of the leases, the lessee may renew the lease, or exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.
Guarantees
In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017.2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.
As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
8. COMMON STOCK
Stock Issued
During 2015,2017, Southern Company issued approximately 6.614.6 million shares of common stock primarily through the Omnibus Incentive Compensation Planemployee equity compensation plans and received proceeds of approximately $256$659 million. During
In addition, during the first nine monthssecond and third quarters of 2015, all sales under the Southern Investment Plan and the Employee Savings Plan were funded with shares acquired on the open market by independent plan administrators. In October 2015,2017, Southern Company began issuingissued a total of approximately 2.7 million shares of common stock through theat-the-market issuances pursuant to sales agency agreements related to Southern Investment PlanCompany's continuous equity offering program and the Employee Savings Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators.
On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises, until December 31, 2017. Repurchases may be made by means of open market purchases, privately negotiated transactions, or accelerated or other share repurchase programs, in accordance with applicable securities laws. Under this program, approximately 2.6 million shares were repurchased in 2015 at a total costreceived cash proceeds of approximately $115 million. No further repurchases under the program are anticipated.$134 million, net of $1.1 million in fees and commissions.
Shares Reserved
At December 31, 20152017, a total of 10671 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan,employee savings plans, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below)., and an at-the-market program. Of the total 10671 million shares reserved, there were 1413 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 20152017.
Stock-Based Compensation
Stock-based compensation primarily in the form of stock optionsperformance share units and performance sharerestricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. AsIn 2015 and 2016, stock-based compensation consisted exclusively of December 31, 2015, there were 5,405 current and former employees participating in the stock option and performance share unit programs.
Stock Options
Through 2009,units. Beginning in 2017, stock-based compensation granted to employees consisted exclusively of non-qualifiedincludes restricted stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a changeunits in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation grantedaddition to employees in 2015 consisted exclusively of performance share units.
The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
The following table shows the assumptions used in the pricing modelshare units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017, there were 5,112 current and the weighted average grant-date fair value of stock options granted:
|
| | | |
Year Ended December 31 | 2014 | | 2013 |
Expected volatility | 14.6% | | 16.6% |
Expected term (in years) | 5 | | 5 |
Interest rate | 1.5% | | 0.9% |
Dividend yield | 4.9% | | 4.4% |
Weighted average grant-date fair value | $2.20 | | $2.93 |
Southern Company's activityformer employees participating in the stock option, program for 2015 is summarized below:performance share unit, and restricted stock unit programs.
|
| | | | |
| Shares Subject to Option | | Weighted Average Exercise Price |
Outstanding at December 31, 2014 | 39,929,319 |
| | $40.55 |
Exercised | 4,032,729 |
| | 36.84 |
Cancelled | 146,684 |
| | 42.31 |
Outstanding at December 31, 2015 | 35,749,906 |
| | $40.96 |
Exercisable at December 31, 2015 | 25,857,590 |
| | $40.53 |
The number of stock options vested, and expected to vestIn conjunction with the Merger, stock-based compensation in the future, asform of December 31, 2015 was not significantly different from the number of stock options outstanding at December 31, 2015 as stated above. As of December 31, 2015, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately six years and the aggregate intrinsic value for the options outstanding and options exercisable was $209 million and $162 million, respectively.
For the years ended December 31, 2015, 2014, and 2013, total compensation cost for stock option awards recognized in income was $6 million, $27 million, and $25 million, respectively, with the related tax benefit also recognized in income of $2 million, $10 million, and $10 million, respectively. As of December 31, 2015, the total unrecognized compensation cost related to stock option awards not yet vested was immaterial.
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $48 million, $125 million, and $77 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $19 million, $48 million, and $30 million for the years ended December 31, 2015, 2014, and 2013, respectively.
Southern Company has a policyrestricted stock and performance share units was also granted to certain executives of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises underSouthern Company Gas through the share-based payment arrangements for the years ended December 31, 2015, 2014, and 2013 was $154 million, $400 million, and $204 million, respectively.Southern Company Omnibus Incentive Compensation Plan.
Performance Share Units
From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period which equates to the requisite service period for accounting purposes.period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
The performance goal for allSouthern Company issues performance share units issued from 2010 through 2014 waswith performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For thesepeers, performance share units at the end of three years, active employees receive shareswith performance goals based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service duringcumulative earnings per share (EPS) over the performance period, prior to retirement. and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative EPS over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. TheEmployees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee.retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
In determining the fair value of the TSR-based awards issued to employees, the expected volatility wasis based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate wasis based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
| | Year Ended December 31 | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Expected volatility | 12.9% | | 12.6% | | 12.0% | 15.6% | | 15.0% | | 12.9% |
Expected term (in years) | 3 | | 3 | | 3 | 3 | | 3 | | 3 |
Interest rate | 1.0% | | 0.6% | | 0.4% | 1.4% | | 0.8% | | 1.0% |
Annualized dividend rate(*) | N/A | | $2.03 | | $1.96 | |
Weighted average grant-date fair value | $46.38 | | $37.54 | | $40.50 | $49.08 | | $45.06 | | $46.38 |
| |
(*) | Beginning in 2015, cash dividends paid on Southern Company's common stock are accumulated and payable in additional shares of Southern Company's common stock at the end of the three-year performance period and are embedded in the grant date fair value which equates to the grant date stock price. |
The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21, $48.87, and $47.75, respectively.
Total unvested performance share units outstanding as of December 31, 20142016 were 1,830,381.3.2 million. During 2015, 1,542,6532017, 1.2 million performance share units were granted 812,740and 1.5 million performance share units were vested and 79,902 performance share units wereor forfeited, resulting in 2,480,392 2.9 million
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
unvested performance share units outstanding at December 31, 2015. In January 2016, based on achievement2017. The number of the TSR performance goal, a portion of the performance share award units granted in 2013 vested and 227,515 shares wereto be issued at a share price of $46.80 for the three-year performance and vesting period ended December 31, 2015.2017 will be determined in the first quarter 2018.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, total compensation cost for performance share units recognized in income was $88$74 million, $33$96 million, and $31$88 million, respectively, with the related tax benefit also recognized in income of $34$29 million, $13$37 million, and $12$34 million, respectively. As of December 31, 2015, there was $332017, $30 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 1921 months.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25.
During 2017, 0.6 million restricted stock units were granted and 0.1 million restricted stock units were vested or forfeited, resulting in 0.7 million unvested restricted stock units outstanding at December 31, 2017, including previously issued restricted stock units related to other employee retention agreements.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $25 million with the related tax benefit also recognized in income of $10 million. As of December 31, 2017, $8 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.
Stock Options
In 2015, Southern Company discontinued the granting of stock options and all outstanding options have vested. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
Southern Company's activity in the stock option program for 2017 is summarized below:
|
| | | | | | |
| Shares Subject to Option | | Weighted Average Exercise Price |
| (in millions) | | |
Outstanding at December 31, 2016 | 24.6 |
| | $ | 41.28 |
|
Exercised | 6.0 |
| | 40.03 |
|
Cancelled | — |
| | 39.90 |
|
Outstanding and Exercisable at December 31, 2017 | 18.6 |
| | $ | 41.68 |
|
As of December 31, 2017, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately five years and the aggregate intrinsic value for the options outstanding and options exercisable was $119 million.
Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $64 million, $120 million, and $48 million, respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $25 million, $46 million, and $19 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2017, 2016, and 2015 was $239 million, $448 million, and $154 million, respectively.
Southern Company Gas Restricted Stock Awards
At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 0.7 million restricted stock units with a grant-date fair value of $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration.
For the years ended December 31, 2017 and 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million, respectively, and the related tax benefit also recognized in income was $4 million for each year. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months.
Southern Company Gas Change in Control Awards
Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares).
The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance.
For the years ended December 31, 2017 and 2016, total compensation cost for the change in control awards recognized in income was $12 million and $4 million, respectively. The related tax benefit also recognized in income was $6 million for the year ended December 31, 2017 and an immaterial amount for the year ended December 31, 2016. As of December 31, 2017, approximately $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months.
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted earnings per shareEPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per shareEPS were as follows:
| | | Average Common Stock Shares | Average Common Stock Shares |
| 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
As reported shares | 910 |
| | 897 |
| | 877 |
| 1,000 |
| | 951 |
| | 910 |
|
Effect of options and performance share award units | 4 |
| | 4 |
| | 4 |
| 8 |
| | 7 |
| | 4 |
|
Diluted shares | 914 |
| | 901 |
| | 881 |
| 1,008 |
| | 958 |
| | 914 |
|
II-111Prior to the adoption of ASU 2016-09 in 2016, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. Stock options and
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Stock options and performance share award units that were not included in the diluted earnings per shareEPS calculation because they were anti-dilutive were 1 million and 7 million as of December 31, 2015 and 2014, respectively.immaterial in all years presented.
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 20152017, consolidated retained earnings included $7.0$5.3 billion of undistributed retained earnings of the subsidiaries.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.5$13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375$450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policyand policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years.exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2017 under the NEIL policies would be $55 million and $84$81 million, respectively.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Companyapplicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 20152017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| |
Energy-related derivatives(a)(b) | | $ | 331 |
| | $ | 239 |
| | $ | — |
| | $ | — |
| | $ | 570 |
|
Interest rate derivatives | — |
| | 22 |
| | — |
| | — |
| | 22 |
| — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Nuclear decommissioning trusts:(*) | | | | | | | | | | |
Foreign currency derivatives | | — |
| | 129 |
| | — |
| | — |
| | 129 |
|
Nuclear decommissioning trusts:(c) | | | | | | | | | | |
Domestic equity | 541 |
| | 69 |
| | — |
| | — |
| | 610 |
| 690 |
| | 82 |
| | — |
| | — |
| | 772 |
|
Foreign equity | 47 |
| | 160 |
| | — |
| | — |
| | 207 |
| 62 |
| | 224 |
| | — |
| | — |
| | 286 |
|
U.S. Treasury and government agency securities | — |
| | 152 |
| | — |
| | — |
| | 152 |
| — |
| | 251 |
| | — |
| | — |
| | 251 |
|
Municipal bonds | — |
| | 64 |
| | — |
| | — |
| | 64 |
| — |
| | 68 |
| | — |
| | — |
| | 68 |
|
Corporate bonds | 11 |
| | 278 |
| | — |
| | — |
| | 289 |
| 21 |
| | 315 |
| | — |
| | — |
| | 336 |
|
Mortgage and asset backed securities | — |
| | 145 |
| | — |
| | — |
| | 145 |
| — |
| | 57 |
| | — |
| | — |
| | 57 |
|
Private equity | — |
| | — |
| | — |
| | 17 |
| | 17 |
| — |
| | — |
| | — |
| | 29 |
| | 29 |
|
Other | 16 |
| | 9 |
| | — |
| | — |
| | 25 |
| 19 |
| | 12 |
| | — |
| | — |
| | 31 |
|
Cash equivalents | 790 |
| | — |
| | — |
| | — |
| | 790 |
| 1,455 |
| | — |
| | — |
| | — |
| | 1,455 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
| 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 1,414 |
| | $ | 906 |
| | $ | 1 |
| | $ | 17 |
| | $ | 2,338 |
| $ | 2,587 |
| | $ | 1,378 |
| | $ | 1 |
| | $ | 29 |
| | $ | 3,995 |
|
Liabilities: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 220 |
| | $ | — |
| | $ | — |
| | $ | 220 |
| |
Energy-related derivatives(a)(b) | | $ | 480 |
| | $ | 253 |
| | $ | — |
| | $ | — |
| | $ | 733 |
|
Interest rate derivatives | — |
| | 30 |
| | — |
| | — |
| | 30 |
| — |
| | 38 |
| | — |
| | — |
| | 38 |
|
Foreign currency derivatives | | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Contingent consideration | | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
Total | $ | — |
| | $ | 250 |
| | $ | — |
| | $ | — |
| | $ | 250 |
| $ | 480 |
| | $ | 314 |
| | $ | 22 |
| | $ | — |
| | $ | 816 |
|
| |
(*)(a) | Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $193 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending pool.program. See Note 1 under "Nuclear Decommissioning""Nuclear Decommissioning" for additional information. |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
As of December 31, 20142016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(b) | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
| $ | 338 |
| | $ | 333 |
| | $ | — |
| | $ | — |
| | $ | 671 |
|
Interest rate derivatives | — |
| | 8 |
| | — |
| | — |
| | 8 |
| — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Nuclear decommissioning trusts:(*) | | | | | | | | | | |
Nuclear decommissioning trusts:(c) | | | | | | | | | | |
Domestic equity | 583 |
| | 85 |
| | — |
| | — |
| | 668 |
| 589 |
| | 73 |
| | — |
| | — |
| | 662 |
|
Foreign equity | 34 |
| | 184 |
| | — |
| | — |
| | 218 |
| 48 |
| | 168 |
| | — |
| | — |
| | 216 |
|
U.S. Treasury and government agency securities | — |
| | 130 |
| | — |
| | — |
| | 130 |
| — |
| | 92 |
| | — |
| | — |
| | 92 |
|
Municipal bonds | — |
| | 62 |
| | — |
| | — |
| | 62 |
| — |
| | 73 |
| | — |
| | — |
| | 73 |
|
Corporate bonds | — |
| | 299 |
| | — |
| | — |
| | 299 |
| 22 |
| | 310 |
| | — |
| | — |
| | 332 |
|
Mortgage and asset backed securities | — |
| | 139 |
| | — |
| | — |
| | 139 |
| — |
| | 183 |
| | — |
| | — |
| | 183 |
|
Private equity | — |
| | — |
| | — |
| | 3 |
| | 3 |
| — |
| | — |
| | — |
| | 20 |
| | 20 |
|
Other | 11 |
| | 13 |
| | — |
| | — |
| | 24 |
| 11 |
| | 15 |
| | — |
| | — |
| | 26 |
|
Cash equivalents | 397 |
| | — |
| | — |
| | — |
| | 397 |
| 1,172 |
| | — |
| | — |
| | — |
| | 1,172 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
| 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 1,034 |
| | $ | 933 |
| | $ | 1 |
| | $ | 3 |
| | $ | 1,971 |
| $ | 2,189 |
| | $ | 1,261 |
| | $ | 1 |
| | $ | 20 |
| | $ | 3,471 |
|
Liabilities: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives(b) | $ | — |
| | $ | 201 |
| | $ | — |
| | $ | — |
| | $ | 201 |
| $ | 345 |
| | $ | 285 |
| | $ | — |
| | $ | — |
| | $ | 630 |
|
Interest rate derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
| — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Foreign currency derivatives | | — |
| | 58 |
| | — |
| | — |
| | 58 |
|
Contingent consideration | | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
Total | $ | — |
| | $ | 225 |
| | $ | — |
| | $ | — |
| | $ | 225 |
| $ | 345 |
| | $ | 372 |
| | $ | 18 |
| | $ | — |
| | $ | 735 |
|
| |
(*)(a) | Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $62 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending pool.program. See Note 1 under "Nuclear Decommissioning""Nuclear Decommissioning" for additional information. |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflectreflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning""Nuclear Decommissioning" for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments havehas been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
Southern Company early adopted ASU 2015-07 effective December 31, 2015. As required, disclosures in the paragraphs and tables below are limited to only those investments in funds that are measured at net asset value as a practical expedient. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation.
As of December 31, 20152017 and 2014,2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) |
|
|
|
|
As of December 31, 2015 | $ | 17 |
|
| $ | 28 |
|
| Not Applicable |
| Not Applicable |
As of December 31, 2014 | $ | 3 |
| | $ | 7 |
| | Not Applicable | | Not Applicable |
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) |
|
|
|
|
As of December 31, 2017 | $ | 29 |
|
| $ | 21 |
|
| Not Applicable |
| Not Applicable |
As of December 31, 2016 | $ | 20 |
| | $ | 25 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high qualityhigh-quality private equity funds across several market sectors, a fundfunds that investsinvest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next ten10 years.
As of December 31, 20152017 and 20142016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2015 | $ | 27,216 |
| | $ | 27,913 |
|
2014 | $ | 23,814 |
| | $ | 25,816 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 48,151 |
| | $ | 51,348 |
|
2016 | $ | 45,080 |
| | $ | 46,286 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Power.Company Gas.
11. DERIVATIVES
The Southern Company the traditional operating companies, and Southern Power aresystem is exposed to market risks, primarilyincluding commodity price risk, interest rate risk, weather risk, and interestoccasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. EachSouthern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information.
Energy-Related Derivatives
The traditional operating companiesSouthern Company and Southern Powercertain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the
NOTES (continued)
Southern Company traditional electric operating companies and Subsidiary Companies 2015 Annual Report
traditional operating companiesnatural gas distribution utilities have limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. Each of the traditional electric operating companies managesand certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, adversely affect results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry.and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 20152017, the net volume of energy-related derivative contracts for natural gas positions totaled 224621 million mmBtu for the Southern Company system, with the longest hedge date of 20202021 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 20172026 for derivatives not designated as hedges.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 532 million mmBtu.
For cash flow hedges, the amounts expectedThe estimated pre-tax gains (losses) related to energy-related derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2016 are immaterial2018 total $(11) million for Southern Company.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At December 31, 2017, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount |
| Interest Rate Received |
| Weighted Average Interest Rate Paid |
| Hedge Maturity Date |
| Fair Value Gain (Loss) December 31, 2017 |
| (in millions) |
|
|
|
|
|
|
| (in millions) |
Cash Flow Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| $ | 900 |
|
| 1-month LIBOR |
| 0.79% |
| March 2018 |
| $ | 1 |
|
Fair Value Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| 250 |
| | 5.40% | | 3-month LIBOR + 4.02% | | June 2018 | | — |
|
| 500 |
| | 1.95% | | 3-month LIBOR + 0.76% | | December 2018 | | (3 | ) |
| 200 |
| | 4.25% | | 3-month LIBOR + 2.46% | | December 2019 | | (1 | ) |
| 300 |
| | 2.75% | | 3-month LIBOR + 0.92% | | June 2020 | | (2 | ) |
| 1,500 |
| | 2.35% | | 1-month LIBOR + 0.87% | | July 2021 | | (31 | ) |
Total | $ | 3,650 |
|
|
|
|
|
|
|
| $ | (36 | ) |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2018 total $(20) million. Deferred gains and losses are expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
At December 31, 2015,2017, the following interest rateforeign currency derivatives were outstanding:
|
| | | | | | | | | | | | | | |
| | Notional Amount |
| Interest Rate Received |
| Weighted Average Interest Rate Paid |
| Hedge Maturity Date |
| Fair Value Gain (Loss) December 31, 2015 |
| | (in millions) |
|
|
|
|
|
|
| (in millions) |
Cash Flow Hedges of Forecasted Debt |
|
|
|
|
|
|
|
|
| | $ | 1,000 |
| | 3-month LIBOR | | 2.37% | | November 2026 | | $ | 1 |
|
| | 1,000 |
| | 3-month LIBOR | | 2.70% | | November 2046 | | (1 | ) |
| | 200 |
|
| 3-month LIBOR |
| 2.93% |
| October 2025 |
| (15 | ) |
| | 80 |
|
| 3-month LIBOR |
| 2.32% |
| December 2026 |
| 1 |
|
Cash Flow Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| | 250 |
|
| 3-month LIBOR + 0.32% |
| 0.75% |
| March 2016 |
| — |
|
| | 200 |
|
| 3-month LIBOR + 0.40% |
| 1.01% |
| August 2016 |
| — |
|
Fair Value Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| | 250 |
|
| 1.30% |
| 3-month LIBOR + 0.17% |
| August 2017 |
| 1 |
|
| | 300 |
| | 2.75% | | 3-month LIBOR + 0.92% | | June 2020 | | 2 |
|
| | 250 |
|
| 5.40% |
| 3-month LIBOR + 4.02% |
| June 2018 |
| 1 |
|
| | 200 |
|
| 4.25% |
| 3-month LIBOR + 2.46% |
| December 2019 |
| 2 |
|
| | 500 |
| | 1.95% | | 3-month LIBOR + 0.76% | | December 2018 | | (3 | ) |
Derivatives not Designated as Hedges |
|
|
|
|
|
|
|
|
|
|
| 65 |
| (a,d) | 3-month LIBOR |
| 2.50% |
| October 2016 | (e) | 1 |
|
| | 47 |
| (b,d) | 3-month LIBOR | | 2.21% | | October 2016 | (e) | 1 |
|
| | 65 |
| (c,d) | 3-month LIBOR | | 2.21% | | November 2016 | (f) | 1 |
|
Total | | $ | 4,407 |
|
|
|
|
|
|
|
| $ | (8 | ) |
| |
(a)
| Swaption at RE Tranquillity LLC. See Note 12 for additional information. |
| |
(b)
| Swaption at RE Roserock LLC. See Note 12 for additional information. |
| |
(c)
| Swaption at RE Garland Holdings LLC. See Note 12 for additional information. |
| |
(d) | Amortizing notional amount. |
| |
(e) | Represents the mandatory settlement date. Settlement amount will be based on a 15-year amortizing swap. |
| |
(f) | Represents the mandatory settlement date. Settlement amount will be based on a 12-year amortizing swap. |
Table of ContentsIndex to Financial Statements |
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
| $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 55 |
|
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 51 |
|
Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 106 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to interest expenseearnings for the next 12-month period ending December 31, 2016 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2046.2018 total $(23) million.
Derivative Financial Statement Presentation and Amounts
At December 31, 2015 and 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | 3 |
| | $ | 7 |
| | Liabilities from risk management activities | $ | 130 |
| | $ | 118 |
|
| Other deferred charges and assets | — |
| | — |
| | Other deferred credits and liabilities | 87 |
| | 79 |
|
Total derivatives designated as hedging instruments for regulatory purposes | | $ | 3 |
| | $ | 7 |
| | | $ | 217 |
| | $ | 197 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | 3 |
| | $ | — |
| | Liabilities from risk management activities | $ | 2 |
| | $ | — |
|
Interest rate derivatives: | Other current assets | 19 |
| | 7 |
| | Liabilities from risk management activities | 23 |
| | 17 |
|
| Other deferred charges and assets | — |
| | 1 |
| | Other deferred credits and liabilities | 7 |
| | 7 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | 22 |
| | $ | 8 |
| | | $ | 32 |
| | $ | 24 |
|
Derivatives not designated as hedging instruments | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | 1 |
| | $ | 6 |
| | Liabilities from risk management activities | $ | 1 |
| | $ | 4 |
|
Interest rate derivatives: | Other current assets | 3 |
| | — |
| | Liabilities from risk management activities | — |
| | — |
|
Total derivatives not designated as hedging instruments | | $ | 4 |
| | $ | 6 |
| | | $ | 1 |
| | $ | 4 |
|
Total | | $ | 29 |
| | $ | 21 |
| | | $ | 250 |
| | $ | 225 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2015 Annual Report
The Company'sits subsidiaries enter into derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contractsthat may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts relatedSouthern Company and certain subsidiaries also utilize master netting agreements to energy-relatedmitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. Fair value amounts of derivative contractsassets and interest rate derivative contracts at December 31, 2015 and 2014liabilities on the balance sheets are presented in the following tables.
|
| | | | | | | | | | | | | | | | |
Fair Value |
Assets | 2015 | | 2014 | | Liabilities | 2015 | | 2014 |
| (in millions) | | | (in millions) |
Energy-related derivatives presented in the Balance Sheet (a) | $ | 7 |
| | $ | 13 |
| | Energy-related derivatives presented in the Balance Sheet (a) | $ | 220 |
| | $ | 201 |
|
Gross amounts not offset in the Balance Sheet (b) | (6 | ) | | (9 | ) | | Gross amounts not offset in the Balance Sheet (b) | (6 | ) | | (9 | ) |
Net energy-related derivative assets | $ | 1 |
| | $ | 4 |
| | Net energy-related derivative liabilities | $ | 214 |
| | $ | 192 |
|
Interest rate derivatives presented in the Balance Sheet (a) | $ | 22 |
| | $ | 8 |
| | Interest rate derivatives presented in the Balance Sheet (a) | $ | 30 |
| | $ | 24 |
|
Gross amounts not offset in the Balance Sheet (b) | (9 | ) | | (8 | ) | | Gross amounts not offset in the Balance Sheet (b) | (9 | ) | | (8 | ) |
Net interest rate derivative assets | $ | 13 |
| | $ | — |
| | Net interest rate derivative liabilities | $ | 21 |
| | $ | 16 |
|
| |
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
At December 31, 2015 and 2014, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | | | | |
| Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (130 | ) | | $ | (118 | ) | | Other regulatory liabilities, current | $ | 3 |
| | $ | 7 |
|
| Other regulatory assets, deferred | (87 | ) | | (79 | ) | | Other regulatory liabilities, deferred | — |
| | — |
|
Total energy-related derivative gains (losses) | | $ | (217 | ) | | $ | (197 | ) | | | $ | 3 |
| | $ | 7 |
|
For the years ended December 31, 2015, 2014, and 2013, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |
| Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
|
|
|
|
|
|
| | Amount |
Derivative Category | 2015 |
|
| 2014 |
|
| 2013 |
|
| Statements of Income Location | 2015 |
|
| 2014 |
|
| 2013 |
|
| (in millions) |
| | (in millions) |
Interest rate derivatives | $ | (22 | ) |
| $ | (16 | ) |
| $ | — |
|
| Interest expense, net of amounts capitalized | $ | (9 | ) |
| $ | (8 | ) |
| $ | (14 | ) |
For the years ended December 31, 2015, 2014, and 2013, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from OCI into earnings were immaterial for Southern Company.
For the years ended December 31, 2015, 2014, and 2013, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial and offset by changes to the carrying value of long-term debt.extent that there are netting arrangements or similar agreements with the counterparties.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
At December 31, 2017 and 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | |
| 2017 | | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 10 |
| $ | 43 |
| | $ | 73 |
| $ | 27 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 7 |
| 24 |
| | 25 |
| 33 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 17 |
| $ | 67 |
| | $ | 98 |
| $ | 60 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 14 |
| | $ | 23 |
| $ | 7 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | 1 |
| 4 |
| | 12 |
| 1 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 34 |
| | 1 |
| 28 |
|
Foreign currency derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| 23 |
| | — |
| 25 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 129 |
| — |
| | — |
| 33 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 133 |
| $ | 75 |
| | $ | 36 |
| $ | 94 |
|
Derivatives not designated as hedging instruments | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 380 |
| $ | 437 |
| | $ | 489 |
| $ | 483 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 170 |
| 215 |
| | 66 |
| 81 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| — |
| | 1 |
| — |
|
Total derivatives not designated as hedging instruments | $ | 550 |
| $ | 652 |
| | $ | 556 |
| $ | 564 |
|
Gross amounts recognized | $ | 700 |
| $ | 794 |
| | $ | 690 |
| $ | 718 |
|
Gross amounts offset(a) | $ | (405 | ) | $ | (598 | ) | | $ | (462 | ) | $ | (524 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 295 |
| $ | 196 |
| | $ | 228 |
| $ | 194 |
|
| |
(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively. |
| |
(b) | Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | | | | |
| Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (34 | ) | | $ | (16 | ) | | Other regulatory liabilities, current | $ | 7 |
| | $ | 56 |
|
| Other regulatory assets, deferred | (18 | ) | | (19 | ) | | Other regulatory liabilities, deferred | 1 |
| | 12 |
|
Total energy-related derivative gains (losses)(*) | | $ | (52 | ) | | $ | (35 | ) | | | $ | 8 |
| | $ | 68 |
|
| |
(*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |
| Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Amount |
| | Amount |
Derivative Category | 2017 |
| 2016 |
| 2015 |
| Statements of Income Location | 2017 |
| 2016 |
| 2015 |
| (in millions) |
| | (in millions) |
Energy-related derivatives | $ | (47 | ) |
| $ | 18 |
|
| $ | — |
|
| Depreciation and amortization | $ | (16 | ) |
| $ | 2 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
| Cost of natural gas | (2 | ) |
| (1 | ) |
| — |
|
Interest rate derivatives | (2 | ) |
| (180 | ) |
| (22 | ) |
| Interest expense, net of amounts capitalized | (21 | ) |
| (18 | ) |
| (9 | ) |
Foreign currency derivatives | 140 |
|
| (58 | ) |
| — |
|
| Interest expense, net of amounts capitalized | (23 | ) |
| (13 | ) |
| — |
|
|
|
|
|
|
|
|
|
|
| Other income (expense), net(*) | 160 |
|
| (82 | ) |
| — |
|
Total | $ | 91 |
|
| $ | (220 | ) |
| $ | (22 | ) |
|
| $ | 98 |
|
| $ | (112 | ) |
| $ | (9 | ) |
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record euro-denominated notes. |
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, the pre-tax effects of energy-relatedinterest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | | | | | |
Derivatives in Fair Value Hedging Relationships |
| Gain (Loss) |
Derivative Category | Statements of Income Location | 2017 | | 2016 | | 2015 |
| | (in millions) |
Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (22 | ) | | $ | (21 | ) | | $ | 2 |
|
For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
NOTES (continued)
Southern Company and interest rateSubsidiary Companies 2017 Annual Report
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company.as follows: |
| | | | | | | | | | | | |
Derivatives Not Designated as Hedging Instruments |
| Unrealized Gain (Loss) Recognized in Income |
|
| Amount |
Derivative Category | Statements of Income Location | 2017 |
| 2016 |
| 2015 |
|
| (in millions) |
Energy-related derivatives | Wholesale electric revenues | $ | (4 | ) |
| $ | 2 |
|
| $ | (5 | ) |
| Fuel | — |
|
| — |
|
| 3 |
|
| Natural gas revenues(*) | (80 | ) |
| 33 |
|
| — |
|
| Cost of natural gas | (2 | ) |
| 3 |
|
| — |
|
Total |
| $ | (86 | ) |
| $ | 38 |
|
| $ | (2 | ) |
| |
(*) | Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2015, Southern Company's2017, the Company had no collateral posted with its derivative counterparties was immaterial.to satisfy these arrangements.
At December 31, 20152017, the fair value of energy-related and interest rate derivative liabilities with contingent features was $52 million.$15 million and $7 million, respectively. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $52$14 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.$7 million for energy-related and interest rate derivative contracts, respectively.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Southern Company system maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the traditional operating companies,value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017, cash collateral posted in these accounts was immaterial. Southern Power areCompany Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2017, cash collateral held on deposit in broker margin accounts was $193 million.
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company the traditional operating companies, and Southern Power only enterenters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company the traditional operating companies, and Southern Power havehas also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the traditional operating companies,counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern PowerCompany Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
12. ACQUISITIONS AND DISPOSITIONS
Southern Company
Proposed Merger with AGL Resources
On August 23, 2015, Southern Company entered intoGas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger Agreement to acquire AGL Resources. Under the termsfor a total purchase price of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged withapproximately $8.0 billion and into AGL Resources. AGL Resources will survive the Merger and becomeSouthern Company Gas became a wholly-owned, direct subsidiary of Southern Company. Upon the consummation of the
The Merger each share of common stock of AGL Resources issued and outstanding immediately prior to the effective time of the Merger (Effective Time), other than shares owned by AGL Resources as treasury stock, shares owned by a subsidiary of AGL Resources, and any shares owned by shareholders who have properly exercised and perfected dissenters' rights, will be converted into the right to receive $66 in cash, without interest and less any applicable withholding taxes (Merger Consideration). Other equity-based securities of AGL Resources will be cancelled for cash consideration or converted into new awards from Southern Company as described in the Merger Agreement.
In accordance with GAAP, the Merger will bewas accounted for using the acquisition method of accounting wherebywith the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
Southern Company Gas Purchase Price | |
| (in millions) |
Current assets | $ | 1,557 |
|
Property, plant, and equipment | 10,108 |
|
Goodwill | 5,967 |
|
Intangible assets | 400 |
|
Regulatory assets | 1,118 |
|
Other assets | 229 |
|
Current liabilities | (2,201 | ) |
Other liabilities | (4,742 | ) |
Long-term debt | (4,261 | ) |
Noncontrolling interest | (174 | ) |
Total purchase price | $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of AGL Resources'the assets acquired and liabilities will be recordedassumed of $6.0 billion is recognized as goodwill.goodwill, which is primarily attributable to positioning the Southern Company expects total cash of $8.2 billionsystem to be requiredprovide natural gas infrastructure to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stockmeet customers' growing energy needs and to fund acquisition-related expenses and financing costs of approximately $200 million.compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will also assume AGL Resources' outstanding indebtedness.not be deductible for tax purposes.
The Merger was approved by AGL Resources' shareholdersvaluation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on November 19, 2015,significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and the waiting period under the Hart-Scott-Rodino Antitrust Improvements Actconsist of 1976 expired on December 4, 2015. Consummationoperating revenues of the Merger remains subject to the satisfaction or waiver$3.9 billion and $1.7 billion and net income of certain closing conditions, including, among others, (i) the approval of the California Public Utilities Commission, Georgia PSC, Illinois Commerce Commission, Maryland PSC,$243 million and New Jersey Board of Public Utilities,$114 million for 2017 and other approvals required under applicable state laws, and the approval of the Federal Communications Commission (FCC) for the transfer of control over the FCC licenses of certain subsidiaries of AGL Resources, (ii) the absence of a judgment, order, decision,2016, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
injunction, ruling, or other finding or agency requirementThe following summarized unaudited pro forma consolidated statement of a governmental entity prohibitingearnings information assumes that the consummationacquisition of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement. Southern Company Gas was completed the required state regulatory applications in the fourth quarter 2015 and the required FCC filings in February 2016. On February 24, 2016, a stipulation and settlement agreement betweenon January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company AGL Resources, the Maryland PSC Staff,Gas debt and the Maryland Office of People's Counsel was filed with the Maryland PSC. The proposed settlement remains subject to the approval of the Maryland PSC. Additionally, Southern Company received the approval of the Virginia State Corporation Commission in February 2016.
Subject to certain limitations, either party may terminate the Merger Agreement if the Merger is not consummated by August 23, 2016, which date may be extended by either party to February 23, 2017 if, on August 23, 2016, all conditions to closing other than those relating to (i) regulatory approvals and (ii) the absence of legal restraints preventing consummation of the Merger (to the extent relating to regulatory approvals) have been satisfied. Upon termination of the Merger Agreement under certain specified circumstances, AGL Resources will be required to pay Southern Company a termination fee of $201 million or reimburse Southern Company's expenses up to $5 million (which reimbursement shall reduce on a dollar-for-dollar basis any termination fee subsequently payable by AGL Resources). Southern Company currently expects to complete the transaction in the second half of 2016.
During 2015, the Company incurred external transaction costs for financing, legal, and consulting servicesadditional interest expense associated with the proposed Merger of approximately $41 million.
The ultimate outcome of these matters cannot be determined at this time.
Merger Financing
borrowings by Southern Company intends to initially fund the cash consideration for the Merger using a mix of debt and equity. Southern Company expects to issue the debt to fund the Merger, Consideration in several tranches including long-dated maturities. The amountand (iv) the elimination of debt issued at each maturity will depend on prevailing market conditions atnonrecurring expenses associated with the timeMerger.
|
| | | | | | |
| 2016 | 2015 |
| | |
Operating revenues (in millions) | $ | 21,791 |
| $ | 21,430 |
|
Net income attributable to Southern Company (in millions) | $ | 2,591 |
| $ | 2,665 |
|
Basic EPS | $ | 2.70 |
| $ | 2.85 |
|
Diluted EPS | $ | 2.68 |
| $ | 2.84 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the offering and other factors. In addition, Southern Company entered intoresults that would have occurred had this acquisition been completed on January 1, 2015 or the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Mergerresults that would be attained in the event long-term financing is not available. See Note 6 under "Bank Credit Arrangements" for additional information regarding the Bridge Agreement.future.
Proposed Acquisition of PowerSecure International, Inc. (Unaudited)
On February 24,In May 2016, Southern Company entered into an Agreement and Planacquired all of Merger to acquire PowerSecure International, Inc. Under the terms of this merger agreement, the stockholdersoutstanding stock of PowerSecure, International, Inc. will be entitled to receivea provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, for each share of common stockresulting in a transaction with a totalan aggregate purchase price of approximately $431$429 million. Following this transaction,As a result, PowerSecure International, Inc. will becomebecame a wholly-owned subsidiary of Southern Company. This transaction is expected to close by
The acquisition of PowerSecure was accounted for using the endacquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the second quarter 2016, subjectacquisition date. The following table presents the final purchase price allocation:
|
| | | |
PowerSecure Purchase Price | |
| (in millions) |
Current assets | $ | 172 |
|
Property, plant, and equipment | 46 |
|
Intangible assets | 106 |
|
Goodwill | 284 |
|
Other assets | 4 |
|
Current liabilities | (121 | ) |
Long-term debt, including current portion | (48 | ) |
Deferred credits and other liabilities | (14 | ) |
Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to among other items, approval byexpected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure International, Inc. stockholdershave been included in Southern Company's consolidated financial statements from the date of acquisition and notification, clearance, and reporting requirements underare immaterial to the Hart-Scott-Rodino Antitrust Improvements Actconsolidated financial results of 1976.Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
Southern Power
During 20152017 and 2014,2016, in accordance with Southern Power'sits overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc. (SRE), the projects set forthdiscussed below. Also, in March 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, Southern Power and the following table. Acquisition-related costs of approximately $4 million were expensed as incurred. The acquisitions do not include any contingent consideration unless specifically noted.class B member are
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
2015now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.
The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017.
|
| | | | | | | | | | | | | |
Project Facility | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Southern Power Percentage Ownership | | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period | Approx. Purchase Price | |
| | (MW) | | | | | | | (in millions) | |
WIND |
Kay Wind | Apex Clean Energy Holdings, LLC December 11, 2015 | 299 | Kay County, OK | 100 | % | | December 12, 2015 | Westar Energy, Inc. and Grant River Dam Authority | 20 years | $ | 481 |
| (b) |
|
Grant Wind | Apex Clean Energy Holdings, LLC | 151 | Grant County, OK | 100 | % | | March 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | $ | 258 |
| (c) |
SOLAR |
Lost Hills Blackwell | First Solar, Inc. (First Solar) April 15, 2015 | 33 | Kern County, CA | 51 | % | (a) | April 17, 2015 | City of Roseville, California/Pacific Gas and Electric Company | 29 years | $ | 73 |
| (d) |
|
North Star | First Solar April 30, 2015 | 61 | Fresno County, CA | 51 | % | (a) | June 20, 2015 | Pacific Gas and Electric Company | 20 years | $ | 208 |
| (e) |
|
Tranquillity | Recurrent Energy, LLC August 28, 2015 | 205 | Fresno County, CA | 51 | % | (a) | Fourth quarter 2016 | Shell Energy North America (US), LP and then Southern California Edison (SCE) | 18 years | $ | 100 |
| (f) |
|
Desert Stateline | First Solar August 31, 2015 | 299 | San Bernardino County, CA | 51 | % | (a) | From December 2015 to third quarter 2016 (h) | SCE | 20 years | $ | 439 |
| (g) |
|
Morelos | Solar Frontier Americas Holding, LLC October 22, 2015 | 15 | Kern County, CA | 90 | % | | November 25, 2015 | Pacific Gas and Electric Company | 20 years | $ | 45 |
| (i) |
|
Roserock | Recurrent Energy, LLC November 23, 2015 | 160 | Pecos County, TX | 51 | % | (a) | Fourth quarter 2016 | Austin Energy | 20 years | $ | 45 |
| (j) |
| | | | | | | | | | |
Garland and Garland A | Recurrent Energy, LLC December 17, 2015 | 205 | Kern County, CA | 51 | % | (a) | Fourth quarter 2016 | SCE | 15 years and 20 years | $ | 49 |
| (k) |
| | | | | | | | | | |
Calipatria | Solar Frontier Americas Holding, LLC February 11, 2016 | 20 | Imperial County, CA | 90 | % | | February 11, 2016 | San Diego Gas & Electric Company | 20 years | $ | 52 |
| (l) |
|
| | | | | | | | | |
Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual/Expected COD | PPA Contract Period |
Business Acquisitions During the Year Ended December 31, 2017 |
Bethel | Wind | Invenergy Wind Global LLC, January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
Cactus Flats(a) | Wind | RES America Developments, Inc. July 31, 2017 | 148 | Concho County, TX | 100 | % | | Third quarter 2018 | 12 years and 15 years |
Business Acquisitions Subsequent to December 31, 2017 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC, January 26, 2018 | 20 | Kern County, CA | 100% of Class B |
| (b) | March 2018 | 20 years |
| |
(a) | On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. |
| |
(b) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federalinterest under a tax benefits with respect to the transaction. At each acquisition, Southern Power acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions.equity partnership agreement. |
| |
(b) | Kay Wind -Business Acquisitions During the Year Ended December 31, 2017 Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million. The total purchase price, including $35 million of contingent consideration, is approximately $481 million. As of December 31, 2015, the fair values of the assets acquired and liabilities assumed were finalized in 2017 and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. |
| |
(c) | Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at
|
|
| | | |
| 2017 |
| (in millions) |
Restricted cash | $ | 16 |
|
CWIP | 534 |
|
Other assets | 5 |
|
Accounts payable | (16 | ) |
Total purchase price | $ | 539 |
|
In 2017, total revenues of $15 million and net income of $17 million, primarily as a result of PTCs, was recognized by Southern Power related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Construction Projects in Progress
During the year ended December 31, 2017, in accordance with its overall growth strategy, Southern Power continued construction on the 345-MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, construction costs included in CWIP related to these projects totaled $188 million. The ultimate outcome of these matters cannot be determined at this time.
Development Projects
During 2017, as part of Southern Power's renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
or nearprojects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. to qualify for 100% PTCs.
The ultimate outcome of this matterthese matters cannot be determined at this time.
| |
(d) | Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million. At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million. The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized.
|
| |
(e) | North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million. At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million. The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The amortization expense for the year ended December 31, 2015 was $1 million. The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter.
|
| |
(f) | Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million. The ultimate outcome of this matter cannot be determined at this time.
|
| |
(g) | Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million. As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes Southern Power's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion. The ultimate outcome of this matter cannot be determined at this time.
|
| |
(h) | Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service.
|
| |
(i) | Morelos - The total purchase price, including the minority owner, Turner Renewable Energy, LLC's (TRE) 10% ownership interest, is approximately $50 million. As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized.
|
| |
(j) | Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million. The ultimate outcome of this matter cannot be determined at this time.
|
| |
(k) | Garland and Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million. The ultimate outcome of this matter cannot be determined at this time.
|
| |
(l) | Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million.
|
NOTES (continued)
The following table presents Southern Company and Subsidiary Companies 2015 Annual Report
2014Power's acquisitions for the year ended December 31, 2016.
|
| | | | | | | | | | | | | | |
Project Facility | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Southern Power Percentage Ownership |
| COD | PPA Counterparties for Plant Output | PPA Contract Period | Approx. Purchase Price |
|
| | (MW) | | | | | | | (in millions) |
|
SOLAR |
Adobe | Sun Edison, LLC April 17, 2014 | 20 |
| Kern County, CA | 90 | % |
| May 21, 2014 | SCE | 20 years | $ | 86 |
| (b) |
| | | | | | | | | | |
Macho Springs | First Solar Development, LLC May 22, 2014 | 50 |
| Luna County, NM | 90 | % |
| May 23, 2014 | El Paso Electric Company | 20 years | $ | 117 |
| (c) |
| | | | | | | | | | |
Imperial Valley | First Solar, October 22, 2014 | 150 |
| Imperial County, CA | 51 | % | (a) | November 26, 2014 | San Diego Gas & Electric Company | 25 years | $ | 505 |
| (d) |
|
| | | | | | | | | | |
Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual COD | PPA Contract Period |
Acquisitions for the Year Ended December 31, 2016 |
Boulder 1 | Solar | SunPower November 16, 2016 | 100 | | Clark County, NV | 51 | % | (a) | December 2016 | 20 years |
Calipatria | Solar | Solar Frontier Americas Holding LLC February 11, 2016 | 20 | | Imperial County, CA | 100 | % | (b) | February 2016 | 20 years |
East Pecos | Solar | First Solar, Inc. March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | March 2017 | 15 years |
Grant Plains | Wind | Apex Clean Energy Holdings, LLC August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | 20 years and 12 years (c) |
Grant Wind | Wind | Apex Clean Energy Holdings, LLC April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | 20 years |
Henrietta | Solar | SunPower July 1, 2016 | 102 | | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
Lamesa | Solar | RES America Developments Inc. July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | April 2017 | 15 years |
Mankato (d) | Natural Gas | Calpine Corporation October 26, 2016 | 375 | | Mankato, MN | 100 | % | | N/A (e) | 10 years |
Passadumkeag | Wind | Quantum Utility Generation, LLC June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
Rutherford | Solar | Cypress Creek Renewables, LLC July 1, 2016 | 74 | | Rutherford County, NC | 100 | % | (b) | December 2016 | 15 years |
Salt Fork | Wind | EDF Renewable Energy, Inc. December 1, 2016 | 174 | | Donley and Gray Counties, TX | 100 | % | | December 2016 | 14 years and 12 years |
Tyler Bluff | Wind | EDF Renewable Energy, Inc. December 21, 2016 | 125 | | Cooke County, TX | 100 | % | | December 2016 | 12 years |
Wake Wind | Wind | Invenergy October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | (f) | October 2016 | 12 years |
| |
(a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
(b) | Adobe - Total purchase price, including theSouthern Power originally purchased 90%, with a minority owner TRE'sowning 10%. During 2017, Southern Power acquired the remaining 10% ownership interest, was $97 million. The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material. interest. |
| |
(c) | Macho Springs - Total purchase price, includingIn addition to the minority owner TRE's 10% ownership interest, was $130 million. The fair values of20-year and 12-year PPAs, the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
(d) | Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completionUnder the terms of the facility (representingPPA and the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0expansion PPA, approximately $442 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by Southern Power for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets, acquired were ultimately recorded as follows: $708 millionprimarily related to property, plant, and equipment, and $20 millionare subject to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material. lien at December 31, 2017. |
Construction Projects
During 2015, in accordance with Southern Power's overall growth strategy, Southern Power constructed or commenced construction of the projects set forth in the table below, in addition to the Tranquillity, Desert Stateline, Roserock, Garland, and Garland A facilities. Total cost of construction incurred for these projects during 2015 was $1.8 billion, of which $1.1 billion remains in CWIP at December 31, 2015.
| |
(e) | The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility. |
| |
(f) | Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%. |
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
Acquisitions During the Year Ended December 31, 2016
Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to Southern Power was approximately $2.6 billion for these acquisitions. In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows:
|
| | | | | | | | | | | | |
Solar Facility | Seller | Approx. Nameplate Capacity | County Location in Georgia | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period | Estimated Construction Cost | |
| | (MW) | | | | | (in millions) | |
Sandhills | N/A | 146 | Taylor | Fourth quarter 2016 | Cobb, Flint, and Sawnee Electric Membership Corporations | 25 years | $ | 260 |
| - | 280 | |
Decatur Parkway | TradeWind Energy, Inc. | 84 | Decatur | December 31, 2015 | Georgia Power(a) | 25 years | Approx. $169 | (c) |
Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 29, 2015 | Georgia Power | 20 years | Approx. $46 | (c) |
Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | Fourth quarter 2016 | Georgia Power(b) | 30 years | $ | 220 |
| - | 230 | (c) |
Pawpaw | Longview Solar, LLC | 30 | Taylor | March 2016 | Georgia Power(a) | 30 years | $ | 70 |
| - | 80 | (c) |
Butler Solar Farm | Strata Solar Development, LLC | 22 | Taylor | February 10, 2016 | Georgia Power | 20 years | Approx. $45 | (c) |
|
| | | |
| 2016 |
| (in millions) |
CWIP | $ | 2,354 |
|
Property, plant, and equipment | 302 |
|
Intangible assets (a) | 128 |
|
Other assets | 52 |
|
Accounts payable | (16 | ) |
Debt | (217 | ) |
Total purchase price | $ | 2,603 |
|
| |
Funded by: | |
Southern Power (b) (c) | $ | 2,345 |
|
Noncontrolling interests (d) (e) | 258 |
|
Total purchase price | $ | 2,603 |
|
| |
(a) | Affiliate PPA approved by the FERC.Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. |
| |
(b) | Affiliate PPA subject to FERC approval.At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. |
| |
(c) | Includes the acquisition priceapproximately $281 million of all outstanding membership interestscontingent consideration, of the respective development entity.which $29 million was payable at December 31, 2017. |
| |
(d) | Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. |
| |
(e) | Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. |
Southern Company Gas
Investment in Southern Natural Gas
In September 2016, Southern Company Gas completed its acquisition from Kinder Morgan, Inc. of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of the acquisition was approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
Acquisition of Remaining Interest in SouthStar
SouthStar Energy Services, LLC (SouthStar) is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont Natural Gas Company, Inc.'s (Piedmont) owning the remaining 15%. In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million.
Proposed Sale of Elizabethtown Gas and Elkton Gas
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
13. SEGMENT AND RELATED INFORMATION
The primary businessbusinesses of the Southern Company system isare electricity sales by the traditional electric operating companies and Southern Power.Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Power.Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $392 million, $419 million, and $417 million in $383 million2017, 2016, and $346 million in 2015, 2014,respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and 2013, respectively.Southern Power were $23 million and $119 million, respectively, in 2017 and $11 million and $17 million, respectively, in 2016. The "All Other" column includes parentthe Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2015, 2014,2017, 2016, and 20132015 was as follows:
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | Electric Utilities | | | | | | | Electric Utilities | |
| Traditional Operating Companies | | Southern Power | | Eliminations | | Total | | All Other | | Eliminations | | Consolidated | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| (in millions) | (in millions) |
2015 | | | | | | | | | | | | | | |
2017 | | |
Operating revenues | $ | 16,491 |
| | $ | 1,390 |
| | $ | (439 | ) | | $ | 17,442 |
| | $ | 152 |
| | $ | (105 | ) | | $ | 17,489 |
| $ | 16,884 |
| $ | 2,075 |
| $ | (419 | ) | $ | 18,540 |
| $ | 3,920 |
| $ | 741 |
| $ | (170 | ) | $ | 23,031 |
|
Depreciation and amortization | 1,772 |
| | 248 |
| | — |
| | 2,020 |
| | 14 |
| | — |
| | 2,034 |
| 1,954 |
| 503 |
| — |
| 2,457 |
| 501 |
| 52 |
| — |
| 3,010 |
|
Interest income | 19 |
| | 2 |
| | 1 |
| | 22 |
| | 6 |
| | (5 | ) | | 23 |
| 14 |
| 7 |
| — |
| 21 |
| 3 |
| 11 |
| (9 | ) | 26 |
|
Earnings from equity method investments | | 1 |
| — |
| — |
| 1 |
| 106 |
| (1 | ) | — |
| 106 |
|
Interest expense | | 820 |
| 191 |
| — |
| 1,011 |
| 200 |
| 490 |
| (7 | ) | 1,694 |
|
Income taxes | | 1,021 |
| (939 | ) | — |
| 82 |
| 367 |
| (307 | ) | — |
| 142 |
|
Segment net income (loss)(a)(b)(c) | | (193 | ) | 1,071 |
| — |
| 878 |
| 243 |
| (279 | ) | — |
| 842 |
|
Total assets | | 72,204 |
| 15,206 |
| (325 | ) | 87,085 |
| 22,987 |
| 2,552 |
| (1,619 | ) | 111,005 |
|
Gross property additions | | 3,836 |
| 268 |
| — |
| 4,104 |
| 1,525 |
| 355 |
| — |
| 5,984 |
|
2016 | | |
Operating revenues | | $ | 16,803 |
| $ | 1,577 |
| $ | (439 | ) | $ | 17,941 |
| $ | 1,652 |
| $ | 463 |
| $ | (160 | ) | $ | 19,896 |
|
Depreciation and amortization | | 1,881 |
| 352 |
| — |
| 2,233 |
| 238 |
| 31 |
| — |
| 2,502 |
|
Interest income | | 6 |
| 7 |
| — |
| 13 |
| 2 |
| 20 |
| (15 | ) | 20 |
|
Earnings from equity method investments | | 2 |
| — |
| — |
| 2 |
| 60 |
| (3 | ) | — |
| 59 |
|
Interest expense | 697 |
| | 77 |
| | — |
| | 774 |
| | 69 |
| | (3 | ) | | 840 |
| 814 |
| 117 |
| — |
| 931 |
| 81 |
| 317 |
| (12 | ) | 1,317 |
|
Income taxes | 1,305 |
| | 21 |
| | — |
| | 1,326 |
| | (132 | ) | | — |
| | 1,194 |
| 1,286 |
| (195 | ) | — |
| 1,091 |
| 76 |
| (216 | ) | — |
| 951 |
|
Segment net income (loss)(a) (b) | 2,186 |
| | 215 |
| | — |
| | 2,401 |
| | (32 | ) | | (2 | ) | | 2,367 |
| 2,233 |
| 338 |
| — |
| 2,571 |
| 114 |
| (230 | ) | (7 | ) | 2,448 |
|
Total assets | 69,052 |
| | 8,905 |
| | (397 | ) | | 77,560 |
| | 1,819 |
| | (1,061 | ) | | 78,318 |
| 72,141 |
| 15,169 |
| (316 | ) | 86,994 |
| 21,853 |
| 2,474 |
| (1,624 | ) | 109,697 |
|
Gross property additions | 5,124 |
| | 1,005 |
| | — |
| | 6,129 |
| | 40 |
| | — |
| | 6,169 |
| 4,852 |
| 2,114 |
| — |
| 6,966 |
| 618 |
| 41 |
| (1 | ) | 7,624 |
|
2014 | | | | | | | | | | | | | | |
2015 | | |
Operating revenues | $ | 17,354 |
| | $ | 1,501 |
| | $ | (449 | ) | | $ | 18,406 |
| | $ | 159 |
| | $ | (98 | ) | | $ | 18,467 |
| $ | 16,491 |
| $ | 1,390 |
| $ | (439 | ) | $ | 17,442 |
| $ | — |
| $ | 152 |
| $ | (105 | ) | $ | 17,489 |
|
Depreciation and amortization | 1,709 |
| | 220 |
| | — |
| | 1,929 |
| | 16 |
| | — |
| | 1,945 |
| 1,772 |
| 248 |
| — |
| 2,020 |
| — |
| 14 |
| — |
| 2,034 |
|
Interest income | 17 |
| | 1 |
| | — |
| | 18 |
| | 3 |
| | (2 | ) | | 19 |
| 19 |
| 2 |
| 1 |
| 22 |
| — |
| 6 |
| (5 | ) | 23 |
|
Earnings from equity method investments | | 1 |
| — |
| — |
| 1 |
| — |
| (1 | ) | — |
| — |
|
Interest expense | 705 |
| | 89 |
| | — |
| | 794 |
| | 43 |
| | (2 | ) | | 835 |
| 697 |
| 77 |
| — |
| 774 |
| — |
| 69 |
| (3 | ) | 840 |
|
Income taxes | 1,056 |
| | (3 | ) | | — |
| | 1,053 |
| | (76 | ) | | — |
| | 977 |
| 1,305 |
| 21 |
| — |
| 1,326 |
| — |
| (132 | ) | — |
| 1,194 |
|
Segment net income (loss)(a) (b) | 1,797 |
| | 172 |
| | — |
| | 1,969 |
| | (3 | ) | | (3 | ) | | 1,963 |
| 2,186 |
| 215 |
| — |
| 2,401 |
| — |
| (32 | ) | (2 | ) | 2,367 |
|
Total assets(c) | 64,300 |
| | 5,233 |
| | (131 | ) | | 69,402 |
| | 1,143 |
| | (312 | ) | | 70,233 |
| |
Total assets | | 69,052 |
| 8,905 |
| (397 | ) | 77,560 |
| — |
| 1,819 |
| (1,061 | ) | 78,318 |
|
Gross property additions | 5,568 |
| | 942 |
| | — |
| | 6,510 |
| | 11 |
| | 1 |
| | 6,522 |
| 5,124 |
| 1,005 |
| — |
| 6,129 |
| — |
| 40 |
| — |
| 6,169 |
|
2013 | | | | | | | | | | | | | | |
Operating revenues | $ | 16,136 |
| | $ | 1,275 |
| | $ | (376 | ) | | $ | 17,035 |
| | $ | 139 |
| | $ | (87 | ) | | $ | 17,087 |
| |
Depreciation and amortization | 1,711 |
| | 175 |
| | — |
| | 1,886 |
| | 15 |
| | — |
| | 1,901 |
| |
Interest income | 17 |
| | 1 |
| | — |
| | 18 |
| | 2 |
| | (1 | ) | | 19 |
| |
Interest expense | 714 |
| | 74 |
| | — |
| | 788 |
| | 36 |
| | — |
| | 824 |
| |
Income taxes | 889 |
| | 46 |
| | — |
| | 935 |
| | (85 | ) | | (1 | ) | | 849 |
| |
Segment net income (loss)(a) (b) | 1,486 |
| | 166 |
| | — |
| | 1,652 |
| | (10 | ) | | 2 |
| | 1,644 |
| |
Total assets(c) | 59,188 |
| | 4,417 |
| | (101 | ) | | 63,504 |
| | 1,064 |
| | (304 | ) | | 64,264 |
| |
Gross property additions | 5,226 |
| | 633 |
| | — |
| | 5,859 |
| | 9 |
| | — |
| | 5,868 |
| |
| |
(a) | Attributable to Southern Company. |
| |
(b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ($2.4 billion after tax) in 2017, $428 million ($264 million after tax) in 2016, and $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in 2013.2015. See Note 3 under "Integrated Coal Gasification Combined Cycle"Kemper County Energy Facility – Kemper IGCC Schedule and Cost Estimate"Estimate" for additional information. |
| |
(c) | NetSegment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of $202Gulf Power's ownership of Plant Scherer Unit 3 of $33 million and $139($20 million of unamortized debt issuance costs as of December 31, 2014 and 2013, respectively.Also net of $488 million and $143 million of deferred tax assets as of December 31, 2014 and 2013, respectively.after tax) in 2017. See Note 13 under "Recently Issued Accounting Standards""Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Products and Services
| | Electric Utilities' Revenues | Year | | Retail | | Wholesale | | Other | | Total | Retail | | Wholesale | | Other | | Total |
| | (in millions) | (in millions) |
2017 | | $ | 15,330 |
| | $ | 2,426 |
| | $ | 784 |
| | $ | 18,540 |
|
2016 | | 15,234 |
| | 1,926 |
| | 781 |
| | 17,941 |
|
2015 | | $ | 14,987 |
| | $ | 1,798 |
| | $ | 657 |
| | $ | 17,442 |
| 14,987 |
| | 1,798 |
| | 657 |
| | 17,442 |
|
2014 | | 15,550 |
| | 2,184 |
| | 672 |
| | 18,406 |
| |
2013 | | 14,541 |
| | 1,855 |
| | 639 |
| | 17,035 |
| |
|
| | | | | | | | | | | | | | | |
Southern Company Gas' Revenues |
Year | Gas Distribution Operations | | Gas Marketing Services | | All Other | | Total |
| (in millions) |
2017 | $ | 3,024 |
| | $ | 860 |
| | $ | 36 |
| | $ | 3,920 |
|
2016 | 1,266 |
| | 354 |
| | 32 |
| | 1,652 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 20152017 Annual Report
14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Consolidated Net Income Attributable to Southern Company | | Per Common Share |
| Operating Revenues | | Operating Income | | | Basic Earnings | | Diluted Earnings | | | | Trading Price Range |
Quarter Ended | | Dividends | | High | | Low |
| (in millions) | | | | | | | | | | |
March 2015 | $ | 4,183 |
| | $ | 957 |
| | $ | 508 |
| | $ | 0.56 |
| | $ | 0.56 |
| | $ | 0.5250 |
| | $ | 53.16 |
| | $ | 43.55 |
|
June 2015 | 4,337 |
| | 1,098 |
| | 629 |
| | 0.69 |
| | 0.69 |
| | 0.5425 |
| | 45.44 |
| | 41.40 |
|
September 2015 | 5,401 |
| | 1,649 |
| | 959 |
| | 1.05 |
| | 1.05 |
| | 0.5425 |
| | 46.84 |
| | 41.81 |
|
December 2015 | 3,568 |
| | 578 |
| | 271 |
| | 0.30 |
| | 0.30 |
| | 0.5425 |
| | 47.50 |
| | 43.38 |
|
| | | | | | | | | | | | | | | |
March 2014 | $ | 4,644 |
| | $ | 700 |
| | $ | 351 |
| | $ | 0.39 |
| | $ | 0.39 |
| | $ | 0.5075 |
| | $ | 44.00 |
| | $ | 40.27 |
|
June 2014 | 4,467 |
| | 1,103 |
| | 611 |
| | 0.68 |
| | 0.68 |
| | 0.5250 |
| | 46.81 |
| | 42.55 |
|
September 2014 | 5,339 |
| | 1,278 |
| | 718 |
| | 0.80 |
| | 0.80 |
| | 0.5250 |
| | 45.47 |
| | 41.87 |
|
December 2014 | 4,017 |
| | 561 |
| | 283 |
| | 0.31 |
| | 0.31 |
| | 0.5250 |
| | 51.28 |
| | 43.55 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Consolidated Net Income Attributable to Southern Company | | Per Common Share |
| Operating Revenues | | Operating Income | | | Basic Earnings | | Diluted Earnings | | | | Trading Price Range |
Quarter Ended | | Dividends | | High | | Low |
| (in millions) | | | | | | | | | | |
March 2017 | $ | 5,771 |
| | $ | 1,306 |
| | $ | 658 |
| | $ | 0.66 |
| | $ | 0.66 |
| | $ | 0.5600 |
| | $ | 51.47 |
| | $ | 47.57 |
|
June 2017 | 5,430 |
| | (1,594 | ) | | (1,381 | ) | | (1.38 | ) | | (1.37 | ) | | 0.5800 |
| | 51.97 |
| | 47.87 |
|
September 2017 | 6,201 |
| | 2,045 |
| | 1,069 |
| | 1.07 |
| | 1.06 |
| | 0.5800 |
| | 50.80 |
| | 46.71 |
|
December 2017 | 5,629 |
| | 794 |
| | 496 |
| | 0.49 |
| | 0.49 |
| | 0.5800 |
| | 53.51 |
| | 47.92 |
|
| | | | | | | | | | | | | | | |
March 2016 | $ | 3,992 |
| | $ | 940 |
| | $ | 489 |
| | $ | 0.53 |
| | $ | 0.53 |
| | $ | 0.5425 |
| | $ | 51.73 |
| | $ | 46.00 |
|
June 2016 | 4,459 |
| | 1,185 |
| | 623 |
| | 0.67 |
| | 0.66 |
| | 0.5600 |
| | 53.64 |
| | 47.62 |
|
September 2016 | 6,264 |
| | 1,917 |
| | 1,139 |
| | 1.18 |
| | 1.17 |
| | 0.5600 |
| | 54.64 |
| | 50.00 |
|
December 2016 | 5,181 |
| | 587 |
| | 197 |
| | 0.20 |
| | 0.20 |
| | 0.5600 |
| | 52.23 |
| | 46.20 |
|
As a result of the revisions to the cost estimate for the Kemper IGCC Southern Companyand its June 2017 suspension, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses onrelated to the Kemper IGCC of $183$208 million ($113185 million after tax) in the fourth quarter 2015, $1502017, $34 million ($9321 million after tax) in the third quarter 2015, $232017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $108 million ($1467 million after tax) in the first quarter 2017, $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2015, $92016, and $53 million ($633 million after tax) in the first quarter 2015, $702016. See Note 3 under "Kemper County Energy Facility" for additional information.
As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, and $380 million ($235 million after tax) in the first quarter 2014.2017. See Note 3 under "Integrated Coal Gasification Combined Cycle"5 for additional information.
The Southern Company system's business is influenced by seasonal weather conditions.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 20112013 through 20152017
Southern Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
| | $ | 16,537 |
| | $ | 17,657 |
| $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Total Assets (in millions)(b)(c) | $ | 78,318 |
| | $ | 70,233 |
| | $ | 64,264 |
| | $ | 62,814 |
| | $ | 58,986 |
| $ | 111,005 |
| | $ | 109,697 |
| | $ | 78,318 |
| | $ | 70,233 |
| | $ | 64,264 |
|
Gross Property Additions (in millions) | $ | 6,169 |
| | $ | 6,522 |
| | $ | 5,868 |
| | $ | 5,059 |
| | $ | 4,853 |
| $ | 5,984 |
| | $ | 7,624 |
| | $ | 6,169 |
| | $ | 6,522 |
| | $ | 5,868 |
|
Return on Average Common Equity (percent)(d) | 11.68 |
| | 10.08 |
| | 8.82 |
| | 13.10 |
| | 13.04 |
| 3.44 |
| | 10.80 |
| | 11.68 |
| | 10.08 |
| | 8.82 |
|
Cash Dividends Paid Per Share of Common Stock | $ | 2.1525 |
| | $ | 2.0825 |
| | $ | 2.0125 |
| | $ | 1.9425 |
| | $ | 1.8725 |
| $ | 2.3000 |
| | $ | 2.2225 |
| | $ | 2.1525 |
| | $ | 2.0825 |
| | $ | 2.0125 |
|
Consolidated Net Income Attributable to Southern Company (in millions)(d) | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
| | $ | 2,350 |
| | $ | 2,203 |
| $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
|
Earnings Per Share — | | | | | | | | | | | | | | | | | | |
Basic | $ | 2.60 |
| | $ | 2.19 |
| | $ | 1.88 |
| | $ | 2.70 |
| | $ | 2.57 |
| $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
| | $ | 2.19 |
| | $ | 1.88 |
|
Diluted | 2.59 |
| | 2.18 |
| | 1.87 |
| | 2.67 |
| | 2.55 |
| 0.84 |
| | 2.55 |
| | 2.59 |
| | 2.18 |
| | 1.87 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 20,592 |
| | $ | 19,949 |
| | $ | 19,008 |
| | $ | 18,297 |
| | $ | 17,578 |
| $ | 24,167 |
| | $ | 24,758 |
| | $ | 20,592 |
| | $ | 19,949 |
| | $ | 19,008 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 1,390 |
| | 977 |
| | 756 |
| | 707 |
| | 707 |
| 1,361 |
| | 1,854 |
| | 1,390 |
| | 977 |
| | 756 |
|
Redeemable preferred stock of subsidiaries | 118 |
| | 375 |
| | 375 |
| | 375 |
| | 375 |
| 324 |
| | 118 |
| | 118 |
| | 375 |
| | 375 |
|
Redeemable noncontrolling interests | 43 |
| | 39 |
| | — |
| | — |
| | — |
| — |
| | 164 |
| | 43 |
| | 39 |
| | — |
|
Long-term debt(a)(b) | 24,688 |
| | 20,644 |
| | 21,205 |
| | 19,143 |
| | 18,492 |
| 44,462 |
| | 42,629 |
| | 24,688 |
| | 20,644 |
| | 21,205 |
|
Total (excluding amounts due within one year) | $ | 46,831 |
| | $ | 41,984 |
| | $ | 41,344 |
| | $ | 38,522 |
| | $ | 37,152 |
| $ | 70,314 |
| | $ | 69,523 |
| | $ | 46,831 |
| | $ | 41,984 |
| | $ | 41,344 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 44.0 |
| | 47.5 |
| | 46.0 |
| | 47.5 |
| | 47.3 |
| 34.4 |
| | 35.6 |
| | 44.0 |
| | 47.5 |
| | 46.0 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 3.0 |
| | 2.3 |
| | 1.8 |
| | 1.8 |
| | 1.9 |
| 1.9 |
| | 2.7 |
| | 3.0 |
| | 2.3 |
| | 1.8 |
|
Redeemable preferred stock of subsidiaries | 0.3 |
| | 0.9 |
| | 0.9 |
| | 1.0 |
| | 1.0 |
| 0.5 |
| | 0.2 |
| | 0.3 |
| | 0.9 |
| | 0.9 |
|
Redeemable noncontrolling interests | 0.1 |
| | 0.1 |
| | — |
| | — |
| | — |
| — |
| | 0.2 |
| | 0.1 |
| | 0.1 |
| | — |
|
Long-term debt(a)(b) | 52.6 |
| | 49.2 |
| | 51.3 |
| | 49.7 |
| | 49.8 |
| 63.2 |
| | 61.3 |
| | 52.6 |
| | 49.2 |
| | 51.3 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Other Common Stock Data: | | | | | | | | | | | | | | | | | | |
Book value per share | $ | 22.59 |
| | $ | 21.98 |
| | $ | 21.43 |
| | $ | 21.09 |
| | $ | 20.32 |
| $ | 23.99 |
| | $ | 25.00 |
| | $ | 22.59 |
| | $ | 21.98 |
| | $ | 21.43 |
|
Market price per share: | | | | | | | | | | | | | | | | | | |
High | $ | 53.16 |
| | $ | 51.28 |
| | $ | 48.74 |
| | $ | 48.59 |
| | $ | 46.69 |
| $ | 53.51 |
| | $ | 54.64 |
| | $ | 53.16 |
| | $ | 51.28 |
| | $ | 48.74 |
|
Low | 41.40 |
| | 40.27 |
| | 40.03 |
| | 41.75 |
| | 35.73 |
| 46.71 |
| | 46.00 |
| | 41.40 |
| | 40.27 |
| | 40.03 |
|
Close (year-end) | 46.79 |
| | 49.11 |
| | 41.11 |
| | 42.81 |
| | 46.29 |
| 48.09 |
| | 49.19 |
| | 46.79 |
| | 49.11 |
| | 41.11 |
|
Market-to-book ratio (year-end) (percent) | 207.2 |
| | 223.4 |
| | 191.8 |
| | 203.0 |
| | 227.8 |
| 200.5 |
| | 196.8 |
| | 207.2 |
| | 223.4 |
| | 191.8 |
|
Price-earnings ratio (year-end) (times) | 18.0 |
| | 22.4 |
| | 21.9 |
| | 15.9 |
| | 18.0 |
| 57.3 |
| | 19.1 |
| | 18.0 |
| | 22.4 |
| | 21.9 |
|
Dividends paid (in millions) | $ | 1,959 |
| | $ | 1,866 |
| | $ | 1,762 |
| | $ | 1,693 |
| | $ | 1,601 |
| $ | 2,300 |
| | $ | 2,104 |
| | $ | 1,959 |
| | $ | 1,866 |
| | $ | 1,762 |
|
Dividend yield (year-end) (percent) | 4.6 |
| | 4.2 |
| | 4.9 |
| | 4.5 |
| | 4.0 |
| 4.8 |
| | 4.5 |
| | 4.6 |
| | 4.2 |
| | 4.9 |
|
Dividend payout ratio (percent) | 82.7 |
| | 95.0 |
| | 107.1 |
| | 72.0 |
| | 72.7 |
| 273.2 |
| | 86.0 |
| | 82.7 |
| | 95.0 |
| | 107.1 |
|
Shares outstanding (in thousands): | | | | | | | | | | | | | | | | | | |
Average | 910,024 |
| | 897,194 |
| | 876,755 |
| | 871,388 |
| | 856,898 |
| 1,000,336 |
| | 951,332 |
| | 910,024 |
| | 897,194 |
| | 876,755 |
|
Year-end | 911,721 |
| | 907,777 |
| | 887,086 |
| | 867,768 |
| | 865,125 |
| 1,007,603 |
| | 990,394 |
| | 911,721 |
| | 907,777 |
| | 887,086 |
|
Stockholders of record (year-end) | 131,771 |
| | 137,369 |
| | 143,800 |
| | 149,628 |
| | 155,198 |
| 120,803 |
| | 126,338 |
| | 131,771 |
| | 137,369 |
| | 143,800 |
|
Traditional Operating Company Customers (year-end) (in thousands): | | | | | | | | | | |
Residential | 3,928 |
| | 3,890 |
| | 3,859 |
| | 3,832 |
| | 3,809 |
| |
Commercial(c) | 591 |
| | 587 |
| | 582 |
| | 579 |
| | 578 |
| |
Industrial(c) | 16 |
| | 16 |
| | 16 |
| | 16 |
| | 16 |
| |
Other | 11 |
| | 11 |
| | 10 |
| | 9 |
| | 9 |
| |
Total | 4,546 |
| | 4,504 |
| | 4,467 |
| | 4,436 |
| | 4,412 |
| |
Employees (year-end) | 26,703 |
| | 26,369 |
| | 26,300 |
| | 26,439 |
| | 26,377 |
| |
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million $139 million, $133 million, and $156$139 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b)(c) | A reclassification of deferred tax assets from Total Assets of $488 million $143 million, $202 million, and $125$143 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-17.new accounting standards adopted in 2015 and applied retrospectively. |
(d) | A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 6,515 |
| | $ | 6,614 |
| | $ | 6,383 |
| | $ | 6,499 |
| | $ | 6,011 |
|
Commercial | 5,439 |
| | 5,394 |
| | 5,317 |
| | 5,469 |
| | 5,214 |
|
Industrial | 3,262 |
| | 3,171 |
| | 3,172 |
| | 3,449 |
| | 3,188 |
|
Other | 114 |
| | 55 |
| | 115 |
| | 133 |
| | 128 |
|
Total retail | 15,330 |
| | 15,234 |
| | 14,987 |
| | 15,550 |
| | 14,541 |
|
Wholesale | 2,426 |
| | 1,926 |
| | 1,798 |
| | 2,184 |
| | 1,855 |
|
Total revenues from sales of electricity | 17,756 |
| | 17,160 |
| | 16,785 |
| | 17,734 |
| | 16,396 |
|
Natural gas revenues | 3,791 |
| | 1,596 |
| | — |
| | — |
| | — |
|
Other revenues | 1,484 |
| | 1,140 |
| | 704 |
| | 733 |
| | 691 |
|
Total | $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 50,536 |
| | 53,337 |
| | 52,121 |
| | 53,347 |
| | 50,575 |
|
Commercial | 52,340 |
| | 53,733 |
| | 53,525 |
| | 53,243 |
| | 52,551 |
|
Industrial | 52,785 |
| | 52,792 |
| | 53,941 |
| | 54,140 |
| | 52,429 |
|
Other | 846 |
| | 883 |
| | 897 |
| | 909 |
| | 902 |
|
Total retail | 156,507 |
| | 160,745 |
| | 160,484 |
| | 161,639 |
| | 156,457 |
|
Wholesale sales | 49,034 |
| | 37,043 |
| | 30,505 |
| | 32,786 |
| | 26,944 |
|
Total | 205,541 |
| | 197,788 |
| | 190,989 |
| | 194,425 |
| | 183,401 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.89 |
| | 12.40 |
| | 12.25 |
| | 12.18 |
| | 11.89 |
|
Commercial | 10.39 |
| | 10.04 |
| | 9.93 |
| | 10.27 |
| | 9.92 |
|
Industrial | 6.18 |
| | 6.01 |
| | 5.88 |
| | 6.37 |
| | 6.08 |
|
Total retail | 9.80 |
| | 9.48 |
| | 9.34 |
| | 9.62 |
| | 9.29 |
|
Wholesale | 4.95 |
| | 5.20 |
| | 5.89 |
| | 6.66 |
| | 6.88 |
|
Total sales | 8.64 |
| | 8.68 |
| | 8.79 |
| | 9.12 |
| | 8.94 |
|
Average Annual Kilowatt-Hour | | | | | | | | | |
Use Per Residential Customer | 11,618 |
| | 12,387 |
| | 13,318 |
| | 13,765 |
| | 13,144 |
|
Average Annual Revenue | | | | | | | | | |
Per Residential Customer | $ | 1,498 |
| | $ | 1,541 |
| | $ | 1,630 |
| | $ | 1,679 |
| | $ | 1,562 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 46,936 |
| | 46,291 |
| | 44,223 |
| | 46,549 |
| | 45,502 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 31,956 |
| | 32,272 |
| | 36,794 |
| | 37,234 |
| | 27,555 |
|
Summer | 34,874 |
| | 35,781 |
| | 36,195 |
| | 35,396 |
| | 33,557 |
|
System Reserve Margin (at peak) (percent)(b) | 30.8 |
| | 34.2 |
| | 33.2 |
| | 19.8 |
| | 21.5 |
|
Annual Load Factor (percent) | 61.4 |
| | 61.5 |
| | 59.9 |
| | 59.6 |
| | 63.2 |
|
Plant Availability (percent): | | | | | | | | | |
Fossil-steam | 84.5 |
| | 86.4 |
| | 86.1 |
| | 85.8 |
| | 87.7 |
|
Nuclear | 94.7 |
| | 93.3 |
| | 93.5 |
| | 91.5 |
| | 91.5 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 112 under "Recently Issued Accounting Standards""Merger with Southern Company Gas" for additional information. |
(c)(b) | Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 27.0 |
| | 30.3 |
| | 32.3 |
| | 39.3 |
| | 36.9 |
|
Nuclear | 14.5 |
| | 14.5 |
| | 15.2 |
| | 14.8 |
| | 15.5 |
|
Oil and gas | 41.9 |
| | 41.7 |
| | 42.7 |
| | 37.0 |
| | 37.2 |
|
Hydro | 2.1 |
| | 2.1 |
| | 2.6 |
| | 2.5 |
| | 3.9 |
|
Other | 5.4 |
| | 2.4 |
| | 0.8 |
| | 0.4 |
| | 0.1 |
|
Purchased power | 9.1 |
| | 9.0 |
| | 6.4 |
| | 6.0 |
| | 6.4 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Gas Sales Volumes (mmBtu in millions): | | | | | | | | | |
Firm | 667 |
| | 296 |
| | — |
| | — |
| | — |
|
Interruptible | 95 |
| | 53 |
| | — |
| | — |
| | — |
|
Total | 762 |
| | 349 |
| | — |
| | — |
| | — |
|
Traditional Electric Operating Company Customers (year-end) (in thousands): | | | | | | | | | |
Residential | 4,011 |
| | 3,970 |
| | 3,928 |
| | 3,890 |
| | 3,859 |
|
Commercial(b) | 599 |
| | 595 |
| | 590 |
| | 586 |
| | 582 |
|
Industrial(b) | 18 |
| | 17 |
| | 17 |
| | 17 |
| | 17 |
|
Other | 12 |
| | 11 |
| | 11 |
| | 11 |
| | 9 |
|
Total electric customers | 4,640 |
| | 4,593 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Gas distribution operations customers | 4,623 |
| | 4,586 |
| | — |
| | — |
| | — |
|
Total utility customers | 9,263 |
| | 9,179 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Employees (year-end) | 31,344 |
| | 32,015 |
| | 26,703 |
| | 26,369 |
| | 26,300 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of customers from commercial to industrial is reflected for years 2011-20132013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2011 through 2015
Southern Company and Subsidiary Companies 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 6,383 |
| | $ | 6,499 |
| | $ | 6,011 |
| | $ | 5,891 |
| | $ | 6,268 |
|
Commercial | 5,317 |
| | 5,469 |
| | 5,214 |
| | 5,097 |
| | 5,384 |
|
Industrial | 3,172 |
| | 3,449 |
| | 3,188 |
| | 3,071 |
| | 3,287 |
|
Other | 115 |
| | 133 |
| | 128 |
| | 128 |
| | 132 |
|
Total retail | 14,987 |
| | 15,550 |
| | 14,541 |
| | 14,187 |
| | 15,071 |
|
Wholesale | 1,798 |
| | 2,184 |
| | 1,855 |
| | 1,675 |
| | 1,905 |
|
Total revenues from sales of electricity | 16,785 |
| | 17,734 |
| | 16,396 |
| | 15,862 |
| | 16,976 |
|
Other revenues | 704 |
| | 733 |
| | 691 |
| | 675 |
| | 681 |
|
Total | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
| | $ | 16,537 |
| | $ | 17,657 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 52,121 |
| | 53,347 |
| | 50,575 |
| | 50,454 |
| | 53,341 |
|
Commercial | 53,525 |
| | 53,243 |
| | 52,551 |
| | 53,007 |
| | 53,855 |
|
Industrial | 53,941 |
| | 54,140 |
| | 52,429 |
| | 51,674 |
| | 51,570 |
|
Other | 897 |
| | 909 |
| | 902 |
| | 919 |
| | 936 |
|
Total retail | 160,484 |
| | 161,639 |
| | 156,457 |
| | 156,054 |
| | 159,702 |
|
Wholesale sales | 30,505 |
| | 32,786 |
| | 26,944 |
| | 27,563 |
| | 30,345 |
|
Total | 190,989 |
| | 194,425 |
| | 183,401 |
| | 183,617 |
| | 190,047 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.25 |
| | 12.18 |
| | 11.89 |
| | 11.68 |
| | 11.75 |
|
Commercial | 9.93 |
| | 10.27 |
| | 9.92 |
| | 9.62 |
| | 10.00 |
|
Industrial | 5.88 |
| | 6.37 |
| | 6.08 |
| | 5.94 |
| | 6.37 |
|
Total retail | 9.34 |
| | 9.62 |
| | 9.29 |
| | 9.09 |
| | 9.44 |
|
Wholesale | 5.89 |
| | 6.66 |
| | 6.88 |
| | 6.08 |
| | 6.28 |
|
Total sales | 8.79 |
| | 9.12 |
| | 8.94 |
| | 8.64 |
| | 8.93 |
|
Average Annual Kilowatt-Hour | | | | | | | | | |
Use Per Residential Customer | 13,318 |
| | 13,765 |
| | 13,144 |
| | 13,187 |
| | 13,997 |
|
Average Annual Revenue | | | | | | | | | |
Per Residential Customer | $ | 1,630 |
| | $ | 1,679 |
| | $ | 1,562 |
| | $ | 1,540 |
| | $ | 1,645 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 44,223 |
| | 46,549 |
| | 45,502 |
| | 45,740 |
| | 43,555 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 36,794 |
| | 37,234 |
| | 27,555 |
| | 31,705 |
| | 34,617 |
|
Summer | 36,195 |
| | 35,396 |
| | 33,557 |
| | 35,479 |
| | 36,956 |
|
System Reserve Margin (at peak) (percent)(a) | 33.2 |
| | 19.8 |
| | 21.5 |
| | 20.8 |
| | 19.2 |
|
Annual Load Factor (percent) | 59.9 |
| | 59.6 |
| | 63.2 |
| | 59.5 |
| | 59.0 |
|
Plant Availability (percent)(b): | | | | | | | | | |
Fossil-steam | 86.1 |
| | 85.8 |
| | 87.7 |
| | 89.4 |
| | 88.1 |
|
Nuclear | 93.5 |
| | 91.5 |
| | 91.5 |
| | 94.2 |
| | 93.0 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 32.3 |
| | 39.3 |
| | 36.9 |
| | 35.2 |
| | 48.7 |
|
Nuclear | 15.2 |
| | 14.8 |
| | 15.5 |
| | 16.2 |
| | 15.0 |
|
Hydro | 2.6 |
| | 2.5 |
| | 3.9 |
| | 1.7 |
| | 2.1 |
|
Oil and gas | 43.5 |
| | 37.4 |
| | 37.3 |
| | 38.3 |
| | 28.0 |
|
Purchased power | 6.4 |
| | 6.0 |
| | 6.4 |
| | 8.6 |
| | 6.2 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
|
| |
(a) | Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. |
(b) | Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
ALABAMA POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 20152017 Annual Report
The management of Alabama Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2015.2017.
/s/ Mark A. Crosswhite
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer
/s/ Philip C. Raymond
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of
Alabama Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014, and2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2015. 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-186 to II-231) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements based on our audits.
We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements (pages II-159 to II-203) present fairly, in all material respects, the financial position of Alabama Power Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
AFUDC | Allowance for funds used during construction |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
DOE | U.S. Department of Energy |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
NDR | Natural Disaster Reserve |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company(excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreement |
PSC | Public Service Commission |
Rate CNP | Rate Certificated New Plant |
Rate CNP Compliance | Rate Certificated New Plant Compliance |
Rate CNP Environmental | Rate Certificated New Plant Environmental |
Rate CNP PPA | Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Rate Energy Cost Recovery |
Rate NDR | Rate Natural Disaster Reserve |
Rate RSE | Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
DEFINITIONS
(continued)
|
Tax Reform Legislation | |
Term | MeaningThe Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 20152017 Annual Report
OVERVIEW
Business Activities
Alabama Power Company (the Company) operates as a vertically integrated utility providing electricityelectric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. The Company has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
Key Performance Indicators
The Company continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance, which the Company achieved during 2015.performance.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The Company's fossil/hydro 2015 Peak Season EFOR of 1.89% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance. The Company's performance for 2015 was below the target for transmission reliability measures primarily due to the level of storm activity in the service territory during the year and was better than target for distribution reliability measures.
The Company uses net income after dividends on preferred and preference stock as the primary measure of the Company's financial performance. See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Earnings
The Company's 20152017 net income after dividends on preferred and preference stock was $785$848 million, representing a $24$26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.
The Company's 2016 net income after dividends on preferred and preference stock was $822 million, representing a $37 million, or 4.7%, increase over the previous year. The increase was due primarily to an increase in ratesretail revenues under Rate RSE effective January 1, 2015. This increase was partially offset by a decrease in weather-related revenues resulting from milder weather experienced in 2015 as compared to 2014 and an increase in amortization.
The Company's 2014 net income after dividends on preferred and preference stock was $761 million, representing a $49 million, or 6.9%, increase over the previous year. The increase was due primarily toCNP Compliance, an increase in weather-related revenues, resulting from colder weatherand a decrease in the first quarter 2014operations and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, an increase in revenuesmaintenance expenses not related to net investments underfuel or Rate CNP Environmental, and an increase in AFUDC resulting from increased capital expenditures. The factors increasing netCompliance. These increases to income were partially offset by an accrual for a Rate RSE refund, a decrease in AFUDC equity, and an increase in total operating expenses.depreciation.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
RESULTS OF OPERATIONS
A condensed income statement for the Company follows:
| | | Amount | | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Operating revenues | $ | 5,768 |
| | $ | (174 | ) | | $ | 324 |
| $ | 6,039 |
| | $ | 150 |
| | $ | 121 |
|
Fuel | 1,342 |
| | (263 | ) | | (26 | ) | 1,225 |
| | (72 | ) | | (45 | ) |
Purchased power | 351 |
| | (34 | ) | | 156 |
| 328 |
| | (6 | ) | | (17 | ) |
Other operations and maintenance | 1,501 |
| | 33 |
| | 179 |
| 1,652 |
| | 142 |
| | 9 |
|
Depreciation and amortization | 643 |
| | 40 |
| | (42 | ) | 736 |
| | 33 |
| | 60 |
|
Taxes other than income taxes | 368 |
| | 12 |
| | 8 |
| 384 |
| | 4 |
| | 12 |
|
Total operating expenses | 4,205 |
| | (212 | ) | | 275 |
| 4,325 |
| | 101 |
| | 19 |
|
Operating income | 1,563 |
| | 38 |
| | 49 |
| 1,714 |
| | 49 |
| | 102 |
|
Allowance for equity funds used during construction | 60 |
| | 11 |
| | 17 |
| 39 |
| | 11 |
| | (32 | ) |
Interest income | 15 |
| | — |
| | (1 | ) | |
Interest expense, net of amounts capitalized | 274 |
| | 19 |
| | (4 | ) | 305 |
| | 3 |
| | 28 |
|
Other income (expense), net | (47 | ) | | (25 | ) | | 14 |
| (14 | ) | | 7 |
| | 11 |
|
Income taxes | 506 |
| | (6 | ) | | 34 |
| 568 |
| | 37 |
| | 25 |
|
Net income | 811 |
| | 11 |
| | 49 |
| 866 |
| | 27 |
| | 28 |
|
Dividends on preferred and preference stock | 26 |
| | (13 | ) | | — |
| 18 |
| | 1 |
| | (9 | ) |
Net income after dividends on preferred and preference stock | $ | 785 |
| | $ | 24 |
| | $ | 49 |
| $ | 848 |
| | $ | 26 |
| | $ | 37 |
|
Operating Revenues
Operating revenues for 20152017 were $5.8$6.0 billion, reflecting a $174$150 million decreaseincrease from 2014.2016. Details of operating revenues were as follows: | | | Amount | Amount |
| 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Retail — prior year | $ | 5,249 |
| | $ | 4,952 |
| $ | 5,322 |
| | $ | 5,234 |
|
Estimated change resulting from — | | | | | | |
Rates and pricing | 204 |
| | 81 |
| 362 |
| | 147 |
|
Sales growth (decline) | (11 | ) | | 7 |
| |
Sales decline | | (44 | ) | | (20 | ) |
Weather | (43 | ) | | 85 |
| (89 | ) | | 31 |
|
Fuel and other cost recovery | (165 | ) | | 124 |
| (93 | ) | | (70 | ) |
Retail — current year | 5,234 |
| | 5,249 |
| 5,458 |
| | 5,322 |
|
Wholesale revenues — | | | | | | |
Non-affiliates | 241 |
| | 281 |
| 276 |
| | 283 |
|
Affiliates | 84 |
| | 189 |
| 97 |
| | 69 |
|
Total wholesale revenues | 325 |
| | 470 |
| 373 |
| | 352 |
|
Other operating revenues | 209 |
| | 223 |
| 208 |
| | 215 |
|
Total operating revenues | $ | 5,768 |
| | $ | 5,942 |
| $ | 6,039 |
| | $ | 5,889 |
|
Percent change | (2.9 | )% | | 5.8 | % | 2.6 | % | | 2.1 | % |
Retail revenues in 20152017 were $5.2$5.5 billion. These revenues decreased $15increased $136 million, or 0.3%2.6%, in 20152017 and increased $297$88 million, or 6.0%1.7%, in 2014,2016, each as compared to the prior year. The decreaseincrease in 20152017 was primarily due to decreasedan increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and milder weather in the first and third quarters 2017
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
2015 as compared to 2014, partially offset by increased revenues due to a Rate RSE increase effective January 1, 2015. The increase in 2014 was due to increased fuel revenues, colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, and increased2016. The increase in 2016 was due to an increase in revenues related to net investments under Rate CNP Environmental primarily resulting from the inclusionCompliance as a result of pre-2005 environmental assets.increased net investments, partially offset by a decrease in fuel revenues and an accrual for a Rate RSE refund. See Note 3 to the financial statements under "Retail Regulatory Matters"Matters – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales growthdecline and weather.
Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Wholesale revenues from power sales to non-affiliated utilities were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Capacity and other | $ | 140 |
| | $ | 154 |
| | $ | 143 |
| $ | 154 |
| | $ | 154 |
| | $ | 140 |
|
Energy | 101 |
| | 127 |
| | 105 |
| 122 |
| | 129 |
| | 101 |
|
Total non-affiliated | $ | 241 |
| | $ | 281 |
|
| $ | 248 |
| $ | 276 |
| | $ | 283 |
| | $ | 241 |
|
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact onaffect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy.
In 2015,2017, wholesale revenues from sales to non-affiliates decreased $40$7 million, or 14.2%2.5%, as compared to the prior year. This decrease reflects a $26 million decrease in revenues from energy sales and a $14 million decrease in capacity revenues. In 2015, KWH sales decreased 6.3% primarily due to the market availability of lower cost natural gas resources and an 8.4% decrease in the price of energy due to lower natural gas prices. In 2014,2016, wholesale revenues from sales to non-affiliates increased $33$42 million, or 13.3%17.4%, as compared to the prior year primarily due to the availability of the Company's lower cost generation. This increase reflects a $22$28 million increase in revenues from energy sales and an $11a $14 million increase in capacity revenues. In 2014,2016, KWH sales increased 12.3%33.3% primarily due to a new contract that became effective in the availability of the Company's lower cost generation andfirst quarter 2016 partially offset by a 1.1% increase12.1% decrease in the price of energy primarily due to higherlower natural gas prices.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clause.
In 2015,2017, wholesale revenues from sales to affiliates decreased $105increased $28 million, or 55.6%40.6%, as compared to the prior year. In 2015,2017, KWH sales decreased 33.9%increased 31.1% as a result of lower costsupporting Southern Company system transmission reliability and a 6.9% increase in the price of energy primarily due to higher natural gas prices. In 2016, wholesale revenues from sales to affiliates decreased $15 million, or 17.9%, as compared to the prior year. In 2016, KWH sales decreased 15.7% as a result of lower-cost generation available in the Southern Company system and a 32.8%2.6% decrease in the price of energy primarily due to lower natural gas prices. In 2014, wholesale revenues from sales to affiliates decreased $23 million, or 10.8%, as compared to the prior year primarily related to a decrease in revenue from energy sales. In 2014, KWH sales decreased 21.7% primarily due to decreased hydro generation as the result of less rainfall as well as the addition of new generation in the Southern Company system, partially offset by a 13.7% increase in the price of energy primarily due to higher natural gas prices.
In 2015, other operating revenues decreased $14 million, or 6.3%, as compared to the prior year primarily due to decreases in co-generation steam revenues due to lower natural gas prices and transmission revenues related to the open access transmission tariff, partially offset by an increase in transmission service agreement revenues. In 2014, other operating revenues increased $17 million, or 8.3%, as compared to the prior year primarily due to increases in open access transmission tariff revenues, transmission service agreement revenues, and co-generation steam revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 20152017 and the percent change from the prior year were as follows:
| | | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2015 | | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in billions) | | | | | | | | | (in billions) | | | | | | | | |
Residential | 18.1 |
| | (3.4 | )% | | 4.5 | % | | 0.1 | % | | (0.8 | )% | 17.2 |
| | (6.1 | )% | | 1.4 | % | | (1.2 | )% | | (0.5 | )% |
Commercial | 14.1 |
| | (0.1 | ) | | 1.6 |
| | 0.1 |
| | (1.3 | ) | 13.6 |
| | (3.4 | ) | | (0.1 | ) | | (1.3 | ) | | (0.5 | ) |
Industrial | 23.4 |
| | (1.8 | ) | | 3.9 |
| | (1.8 | ) | | 3.9 |
| 22.7 |
| | 1.7 |
| | (4.6 | ) | | 1.7 |
| | (4.6 | ) |
Other | 0.2 |
| | (4.9 | ) | | — |
| | (4.9 | ) | | — |
| 0.2 |
| | (5.0 | ) | | 3.8 |
| | (5.0 | ) | | 3.8 |
|
Total retail | 55.8 |
| | (1.9 | ) | | 3.5 |
| | (0.7 | )% | | 1.0 | % | 53.7 |
| | (2.3 | ) | | (1.5 | ) | | (0.1 | )% | | (2.2 | )% |
Wholesale — | | | | | | | | | | |
Wholesale | | | | | | | | | | |
Non-affiliates | 4.3 |
| | (6.3 | ) | | 12.3 |
| | | | | 5.5 |
| | (6.5 | ) | | 37.1 |
| | | | |
Affiliates | 3.8 |
| | (33.8 | ) | | (21.7 | ) | | | | | 4.2 |
| | 31.1 |
| | (15.7 | ) | | | | |
Total wholesale | 8.1 |
| | (21.5 | ) | | (9.4 | ) | | | | | 9.7 |
| | 6.6 |
| | 12.5 |
| | | | |
Total energy sales | 63.9 |
| | (4.9 | )% | | 1.3 | % | | | | | 63.4 |
| | (1.0 | )% | | 0.3 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 20152017 were 1.9%2.3% lower than in 2014.2016. Residential sales and commercial sales decreased 6.1% and 3.4% and 0.1%,in 2017, respectively, primarily due primarily to milder weather in 2015 as compared to 2014. Weather-adjusted residential and commercial sales were flat in 2015. Industrial sales decreased 1.8% in 2015 compared to 2014 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals sector. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the industrial sector in 2015.
Retail energy sales in 2014 were 3.5% higher than in 2013. Residential and commercial sales increased 4.5% and 1.6%, respectively, due primarily to colder weather in the first quarter 2014 and warmer weather in the second and third quarters 20142017 as compared to the corresponding periods in 2013.2016. Weather-adjusted residential andsales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales decreased 0.8%were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and 1.3%, respectively, due primarilyan ongoing migration to a decrease inthe electronic commerce business model, partially offset by customer demand in 2014 compared to 2013.growth. Industrial sales increased 3.9%1.7% in 20142017 as compared to 20132016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, automotive and plastics,mining sectors offset by the pipelines and paper sectors.
Retail energy sales in 2016 were 1.5% lower than in 2015. Residential sales increased 1.4% primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015. Commercial sales remained flat in 2016. Weather-adjusted residential sales were flat in 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Industrial sales decreased 4.6% in 2016 compared to 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemical, pipelines, paper, and stone, clay, and glass sectors. Household income, one ofA strong dollar, low oil prices, and weak global growth conditions constrained growth in the primary drivers of residential customer usage, was flatindustrial sector in 2014.2016.
See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Details of the Company's generation and purchased power were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Total generation (billions of KWHs) | 60.9 |
| | 63.6 |
| | 65.3 |
| |
Total purchased power (billions of KWHs) | 6.3 |
| | 6.6 |
| | 4.0 |
| |
Total generation (in billions of KWHs) | | 60.3 |
| | 60.2 |
| | 60.9 |
|
Total purchased power (in billions of KWHs) | | 6.4 |
| | 7.1 |
| | 6.3 |
|
Sources of generation (percent) — | | | | | | | | | | |
Coal | 54 |
| | 54 |
| | 53 |
| 50 |
| | 53 |
| | 54 |
|
Nuclear | 24 |
| | 23 |
| | 21 |
| 24 |
| | 23 |
| | 24 |
|
Gas | 16 |
| | 17 |
| | 17 |
| 20 |
| | 19 |
| | 16 |
|
Hydro | 6 |
| | 6 |
| | 9 |
| 6 |
| | 5 |
| | 6 |
|
Cost of fuel, generated (cents per net KWH) — | | | | | | |
Cost of fuel, generated (in cents per net KWH) — | | | | | | |
Coal | 2.83 |
| | 3.14 |
| | 3.29 |
| 2.60 |
| | 2.75 |
| | 2.83 |
|
Nuclear | 0.81 |
| | 0.84 |
| | 0.84 |
| 0.75 |
| | 0.78 |
| | 0.81 |
|
Gas | 2.94 |
| | 3.69 |
| | 3.38 |
| 2.72 |
| | 2.67 |
| | 2.94 |
|
Average cost of fuel, generated (cents per net KWH)(a) | 2.34 |
| | 2.68 |
| | 2.73 |
| |
Average cost of purchased power (cents per net KWH)(b) | 5.66 |
| | 5.92 |
| | 5.76 |
| |
Average cost of fuel, generated (in cents per net KWH)(a) | | 2.14 |
| | 2.26 |
| | 2.34 |
|
Average cost of purchased power (in cents per net KWH)(b) | | 5.29 |
| | 4.80 |
| | 5.66 |
|
|
| |
(a) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
(b) | Average cost of purchased power includes fuel, energy, and transmission purchased by the Company for tolling agreements where power is generated by the provider. |
Fuel and purchased power expenses were $1.7$1.55 billion in 2015,2017, a decrease of $297$78 million, or 14.9%4.8%, compared to 2014.2016. The decrease was primarily due to a $184$67 million net decrease related to the volume of KWHs generated and purchased and a $42 million decrease in the average cost of fuel, partially offset by a $79$31 million decrease in the volume of KWHs generated, an $18 million decrease related to the volume of KWHs purchased, and a $16 million decreaseincrease in the average cost of purchased power.
Fuel and purchased power expenses were $2.0$1.63 billion in 2014, an increase2016, a decrease of $130$62 million, or 7.0%3.7%, compared to 2013.2015. The increasedecrease was primarily due to a $147$61 million decrease in the average cost of purchased power, and a $59 million decrease in the average cost of fuel, partially offset by a $49 million increase related to the volume of KWHs purchased and a $10 million increase in the average cost of purchased power. These increases were partially offset by a $19 million decrease in the average cost of fuel and an $8 million decrease in the volume of KWHs generated.purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Fuel
Fuel expenses were $1.3 billion in 2015, a decrease of $263 million, or 16.4%, compared to 2014. The decrease was primarily due to a 20.4% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 9.9% decrease in the average cost of KWHs generated by coal, an 8.5% decrease in the volume of KWHs generated by natural gas, and a 4.0% decrease in the volume of KWHs generated by coal. Fuel expenses were $1.6 billion in 2014, a decrease of $26 million, or 1.6%, compared to 2013. The decrease was primarily due to a 4.5% decrease in the average cost of KWHs generated by coal, partially offset by a 30.8% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, and a 9.2% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
Purchased Power – Non-Affiliates
In 2015, purchased power expense from non-affiliates was $171 million, a decrease of $14 million, or 7.6%, compared to 2014. The decrease was primarily due to a 19.5% decrease in the average cost per KWH purchased primarily due to lower gas prices partially offset by a 15.2% increase in the amount of energy purchased due to the market availability of lower cost generation. In 2014, purchased power expense from non-affiliates was $185 million, an increase of $85 million, or 85.0%, compared to 2013. The increase was primarily due to a 42.1% increase in the average cost per KWH purchased primarily due to demand during peak periods and a 28.8% increase in the amount of energy purchased to meet the demand created during cold weather in the first quarter 2014 and the addition of a new PPA in 2014.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Fuel
Fuel expenses were $1.2 billion in 2017, a decrease of $72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of KWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas. Fuel expenses were $1.3 billion in 2016, a decrease of $45 million, or 3.4%, compared to 2015. The decrease was primarily due to a 9.2% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 4.2% and 3.9% decrease in the volume of KWHs generated by nuclear fuel and coal, respectively, and a 3.7% decrease in the average cost of KWHs generated by nuclear fuel, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.
Purchased Power – Affiliates
Purchased power expense from affiliates was $180$158 million in 2015,2017, a decrease of $20$10 million, or 10.0%6.0%, compared to 2014.2016. This decrease was primarily due to a 16.9%17.2% decrease in the amount of energy purchased due to milder weather in 2015 as compared to 2014, partially offset by an 8.3%a 13.9% increase in the average cost per KWH purchased relateddue to steam support at Plant Gaston.higher natural gas prices. Purchased power expense from affiliates was $200$168 million in 2014, an increase2016, a decrease of $71$12 million, or 55.0%6.7%, compared to 2013.2015. This increasedecrease was primarily due to a 96.4% increase in the amount
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
20.7% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 17.5% increase in the amount of energy purchased due to the availability of lower cost Southern Company systemlower-cost generation atcompared to the time of purchase.Company's owned generation.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
In 2015,2017, other operations and maintenance expenses increased $33$142 million, or 2.2%9.4%, as compared to the prior year. AdministrativeDistribution and generaltransmission expenses increased $53$58 million primarily due to vegetation management expenses. Generation costs increased employee benefit costs including pension costs. Nuclear production expenses increased $19$38 million primarily due to outage amortization costs. These increases were partially offset by a decrease in steam productionEmployee benefit costs, of $21 million primarily due to timing of outages. Distribution expenses decreased $12 million primarily due to overhead line maintenance expenses.including pension costs, increased $22 million.
In 2014,2016, other operations and maintenance expenses increased $179$9 million, or 13.9%0.6%, as compared to the prior year. Steam production other power generation, and hydro generation expensescosts increased $110$28 million primarily due to scheduled outagethe timing of generation operating expenses. Transmission and distribution expenses increased $10 million and $7 million, respectively, primarily due to additional vegetation management and other maintenance expenses. These increases were partially offset by a decrease of $32 million in employee benefit costs, including pension costs. The increases in operations and maintenance expenses were primarily Rate CNP compliance-related costs and therefore had no significant impact to net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP Compliance" herein for additional information.
See Note 32 to the financial statements under "Retail Regulatory Matters – Cost of Removal Accounting Order""Pension Plans" for additional information. Distribution and transmission expenses increased $31 million primarily related to increases in maintenance and labor expenses. Nuclear production expenses increased $14 million primarily related to labor expenses.
Depreciation and Amortization
Depreciation and amortization increased $40$33 million, or 6.6%4.7%, in 20152017 as compared to the prior year. The increase in 2015 wasyear primarily due to the amortization of $120 million of the regulatory liability for other cost of removal obligationsadditional plant in 2014,service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by decreases duea decrease in distribution-related depreciation rates. See Note 1 to lower depreciation rates as a result of the depreciation study implemented in January 2015.financial statements under "Depreciation and Amortization" for additional information. Depreciation and amortization decreased $42increased $60 million, or 6.5%9.3%, in 20142016 as compared to the prior year. The decrease in 2014 wasyear primarily due to the amortization of $120 million of the regulatory liability for other cost of removal obligations, partially offset by increases due to depreciation rates related to environmental assets and amortization of certain regulatory assets. See Note 3 to the financial statements under "Retail Regulatory Matters – Cost of Removal Accounting Order" for additional information.compliance-related steam projects placed in service.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $4 million, or 1.1%, in 2017 as compared to the prior year. In 2016, taxes other than income taxes increased $12 million, or 3.4%,3.3% in 20152016 as compared to the prior year. The increase was primarily due to increases in state and municipal utility license tax bases primarily due to an increase in retail revenues. In addition, there were increases in ad valorem taxes increased primarily due to an increase in assessed value of property.
Allowance for Equity Funds Used During Construction
AFUDC equity increased $11 million, or 22.4%39.3%, in 2015 and $17 million, or 53.1% in 20142017 as compared to the prior yearyear. The increase was primarily dueassociated with steam, transmission, and nuclear construction projects. AFUDC equity decreased $32 million, or 53.3%, in 2016 as compared to an increasethe prior year. The decrease was primarily associated with steam generation capital projects being placed in construction projects related to environmental and steam generation.service. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $19$3 million, or 7.5%1.0%, in 20152017 as compared to the prior year. The increaseInterest expense, net of amounts capitalized increased $28 million, or 10.2%, in 2015 was2016 as compared to the prior year primarily due to timing ofan increase in debt issuancesoutstanding and redemptions partially offset by a decreasereduction in interest rates.the amounts capitalized. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.
Other Income (Expense), Net
II-140Other income (expense), net increased $7 million, or 33.3%, in 2017 as compared to the prior year primarily due to increases in unregulated lighting services. Other income (expense), net increased $11 million, or 34.4%, in 2016 as compared to the prior year primarily due to a decrease in donations, partially offset by a decrease in sales of non-utility property.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Other Income (Expense), Net
Other income (expense), net decreased $25 million, or 113.6%, in 2015 as compared to the prior year. The decrease in 2015 was primarily due to an increase in donations and a decrease in sales of non-utility property. Other income (expense), net increased $14 million, or 38.9%, in 2014 as compared to the prior year primarily due to a decrease in non-operating expenses and an increase in sales of non-utility property.
Income Taxes
Income taxes increased $34$37 million, or 7.1%7.0%, in 20142017 as compared to the prior year primarily due to higher pre-tax earnings, an increase in prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to income taxes as a result of Tax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information. Income taxes increased $25 million, or 4.9%, in 2016 as compared to the prior year primarily due to higher pre-tax earnings.
Dividends on Preferred and Preference Stock
Dividends on preferred and preference stock decreased $13increased $1 million, or 33.3%5.9%, in 20152017 as compared to the prior year. Dividends on preferred and preference stock decreased $9 million, or 34.6%, in 2016 as compared to the prior year. The decrease in 2015 was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements under "Redeemable Preferred and Preference Stock" for additional information.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricityelectric service to retail and wholesale customers within its traditional service areaterritory located in the State of Alabama in additionand to wholesale customers in the Southeast. Prices for electricityelectric service provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electricity sales,electric service, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Electric Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's primary business of selling electricity.providing electric service. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs.costs and limited projected demand growth over the next several years. Future earnings in the near term will be impacted by customer growth. Earnings will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings.
On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to federal and statethe transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental statuteslaws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the Company's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate CNP"CNP Compliance" for additional information. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
Environmental Statutes and Regulations
General
The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the Company had invested approximately $3.9 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $349 million, $355 million, and $184 million for 2015, 2014, and 2013, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $851 million from 2016 through 2018, with annual totals of approximately $319 million, $263 million, and $269 million for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Environmental Accounting Order" herein for additional information on planned unit retirements and fuel conversions at the Company.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.
Air Quality
ComplianceThrough 2017, the Company has invested approximately $4.7 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $491 million, $260 million, and $349 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.4 billion from 2018 through 2022, with annual totals of approximately $581 million in 2018, $110 million in 2019, $163 million in 2020, $258 million in 2021, and $268 million in 2022. These estimates do not include any potential compliance costs associated with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Additional controls are currently planned or under consideration to further reduce airregulation of CO2 emissions maintain compliance with existing regulations, and meet new requirements.
In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions to April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each Company unit. On June 29, 2015, the U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from fossil fuel-fired electric generating units. On December 15, 2015,See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the U.S. CourtDisposal of Appeals forCoal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the District of Columbia Circuit remanded the MATS ruleCompany's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliance requirementsfinancial statements under "Asset Retirement Obligations and deadlines.Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozonehas set National Ambient Air Quality StandardStandards (NAAQS). for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in 2012. All areas within the Company's service territory have achieved attainment of the 2008 standard. On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. ThisThe EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are anticipated to be designated nonattainment under the 2015 ozone NAAQS. In 2010, the EPA revised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the vicinity of Company-owned SO2 sources have been designated nonattainment under the 2010 one-hour SO2 NAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance costs could potentiallyresult.
In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that addresses the impacts of the interstate transport of SO2 and NOX emissions from fossil fuel-fired power plants located in upwind states in the eastern half of the U.S. on air quality in downwind states. The Company has fossil fuel-fired generation subject to these requirements. In October 2016, the EPA published a final rule that revised the CSAPR seasonal NOX program, establishing more stringent NOX emissions budgets in Alabama. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
The EPA finalized regional haze regulations in 2005 and 2017. These regulations require additionalstates, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States must submit a revised state implementation plan (SIP) to the EPA by July 31, 2021, demonstrating reasonable progress towards achieving visibility improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October 2017.
The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company's service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS, and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated final designations for the 2012 annual standard in December 2014, and no new nonattainment areas were designated within the Company's service territory.
Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010. No areas within the Company's service territory have been designated as nonattainment under this rule. However, the EPA has finalized a data requirements rule to support additional designation decisions for SO2 in the future, which could result in nonattainment designations for areas within the Company's service territory. Implementation of the revised SO2 standard could require additional reductions in SO2 emissions and increased compliance and operational costs.
In February 2014, the EPA proposed to delete from the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of the Company and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. The Company believes this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units co-owned with Mississippi Power and units owned by SEGCO, which is jointly owned with Georgia Power.
The Company's service territory is subject to the requirements of the Cross State Air Pollution Rule (CSAPR). CSAPR is an emissions trading program that limits SO2 and nitrogen oxide emissions from power plants in 28 states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, but rejected all other pending challenges to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015, the EPA published a proposed revision to CSAPR that would revise existing ozone-season emissions budgets for nitrogen oxide in Alabama. The EPA proposes to finalize this rulemaking by summer 2016.
The EPA finalized regional haze regulations in 2005, with a goal of restoring natural visibility conditions in certain areas (primarily national parks and wilderness areas) by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieve reasonable progress toward the natural visibility conditions goal by 2018 and for each 10-year period thereafter.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs relating to the regulation ofregulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in increased operations and maintenance costs for the Company.
Water Quality
In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities in order to minimize their effects on fish and other aquatic life. The regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020. The Company continues to monitor the ELG rule and anticipates that approximately 1,000 MWs of the Company's generation will not be available after the compliance date. The ultimate impact of this rule will depend on any new rule-making that revises the limitation and applicable dates. The Company does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on the Company's operations or financial condition.
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
Coal Combustion Residuals
In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule requires CCR units to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than November 22, 2016.
The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. As part of this strategy, the Company has developed a compliance plan for the MATS ruleDecember 2019, which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, the Alabama opacity rule, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significantchanges to deadlines and corrective action requirements.
The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule.
Based on cost estimates for closure in place and monitoring of ash ponds pursuant to the CCR Rule, the Company recorded AROs for each CCR unit in 2015. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and resultsinformation regarding the Company's AROs as of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs.December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014. The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.
On November 3, 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and implementation of the final rule and cannot be determined at this time.
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.
Coal Combustion Residuals
The Company currently manages CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at six generating plants. In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the State of Alabama has its own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.
On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulates the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Units at active generating power plants. The CCR Rule does not automatically require closure of CCR Units but includes minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansions of existing units, and active landfills. Failure to meet the minimum criteria can result in the required closure of a CCR Unit. Although the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA's final rule continues to exclude the beneficial use of CCR from regulation.
Based on initial cost estimates for closure in place and groundwater monitoring primarily related to ash ponds pursuant to the CCR Rule, the Company recorded AROs related to the CCR Rule. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the Company expects to continue to periodically update these estimates. The Company is currently completing an analysis of the plan of closure for all ash ponds, including the timing of closure and related cost recovery through regulated rates subject to Alabama PSC approval. Based on the results of that analysis, the Company may accelerate the timing of some ash pond closures which could increase its ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2015.
Global Climate Issues
On October 23,In 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governingrules limiting CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishesfossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goalsperformance standards for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. Atunits (known as the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adoptClean Power Plan or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. OnCPP). In February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stayCPP, which will remain in effect through the resolution of the litigation whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit orchallenging the legality of the CPP and any review by the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the Company's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, including legal challenges filed byproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the traditional operating companies; individual state implementation of the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countries and cannot be determined at this time.countries.
The EPA's greenhouse gasGHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2014 greenhouse gas2016 GHG emissions were approximately 4038 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2015 greenhouse gas2017 GHG emissions on the same basis is approximately 3837 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Retail Regulatory Matters
The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. The Company currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting the Company. See Note 1 to the financial statements and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's rate mechanisms and accounting orders.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, customer refundsthe excess will be required;refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On November 30, 2015,December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for 2016.calendar year 2018. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.2018.
In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service under Rate CNP.service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015,7, 2017, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 20152017 through March 31, 2016.2018. No adjustment to Rate CNP PPA is expected in 2016.2018.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
Rate CNP Environmental allowedCompliance
Rate CNP Compliance allows for the recovery of the Company's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. The Company was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.
On November 30, 2015, the Company made its annual Revenues for Rate CNP Compliance, submission toas recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its cost of complying with governmental mandates for cost year 2016.under recovered balance in Rate CNP Compliance increased 4.5%, or approximately $250 million annually,to a separate regulatory asset. The amortization of the new regulatory
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2016.2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing.
Rate ECR
The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
On December 1, 2015,In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, approved a decreasethe Company reclassified $36 million of its under recovered balance in the Company’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings,a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2016. The approved decrease2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor will have no significant effect on the Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015.as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018,2019, absent a further order from the Alabama PSC.
Rate NDR
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are beingThe regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Rate CNP Compliance. See "Environmental Matters – Environmental StatutesRegulated utility businesses can continue deducting all business interest expense and Regulations" hereinare not eligible for additional information regarding environmental regulations.
In April 2015, as part of its environmental compliance strategy, the Company retired Plant Gorgas Units 6bonus depreciation on capital assets acquired and 7 (200 MWs). Additionally,placed in April 2015, the Company ceased using coal at Plant Barry Units 1service after September 27, 2017. Projects with binding contracts before September 28, 2017 and 2 (250 MWs), but such units willplaced in service after September 27, 2017 remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA, the Company retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer availableeligible for generation. The Company expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas by April 2016.
In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized and recovered through Rate CNP Compliance over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements.
Renewables
On September 16, 2015, the Alabama PSC approved the Company's petition for a Renewable Generation Certificate for up to 500 MWs. This will allow the Company to build its own renewable projects, each less than 80 MWs, or purchase power from other renewable-generated sources.
Cost of Removal Accounting Order
In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferredbonus depreciation under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs previously deferred were fully amortized in December 2014.
Income Tax Matters
Bonus Depreciation
On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Act.
In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $3 million, a $271 million decrease in regulatory assets, and a $2.0 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Alabama PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters – Rate RSE" for additional information.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Federal Tax Reform Legislation" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus depreciation was extended for qualified propertyDepreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service overafter September 27, 2017 remain eligible for bonus depreciation under the next five years.PATH Act. The PATH Act allowsallowed for 50% bonus depreciation for 2015 2016, and 2017;through 2017, 40% bonus depreciation for 2018;2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result inBased on provisional estimates, approximately $220$200 million of positive cash flows is expected to result from bonus depreciation for the 20152017 tax year and approximately $240$90 million for the 20162018 tax year.
Other Matters
In accordance with accounting standards related to employers' accounting for pensions, the Should Southern Company recorded pension costs of $48 million in 2015, $23 million in 2014 and $47 million in 2013. Postretirement benefit costs for the Company were $5 million, $4 million, and $7 million in 2015, 2014, and 2013, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and postretirement benefit costs is capitalized based on construction-related labor charges. Pension and postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income. For more information regarding pension and postretirement benefits, seeNOL in 2018, all of these cash flows may not be fully realized in 2018. See Note 25 to the financial statements.statements under "Current and Deferred Income Taxes" for additional information.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
As a result of the final CCR Rule discussed above, the Company recorded newThe cost estimates for AROs for facilities that are subjectrelated to the disposal of CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.
Givencost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the significant judgment involved in estimating AROs, the Company considers the liabilitiesfinancial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for AROs to be critical accounting estimates.additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
See Note 1Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.be critical accounting estimates.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ForBeginning in 2016, the Company has adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense will decreasedecreased by approximately $24 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $7an $9 million or less change in total annual benefit expense and a $98$128 million or less change in projected obligations.
The Company recorded pension costs of $9 million, $11 million, and $48 million in 2017, 2016, and 2015, respectively. Postretirement benefit costs for the Company were $3 million, $4 million, and $5 million in 2017, 2016, and 2015, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and other postretirement benefit costs is capitalized based on construction-related labor charges. Pension and other postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers revises(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition effectivewith a five-step model for fiscal years beginning after December 15, 2017.recognizing and measuring revenue from contracts with customers. The Company continues to evaluate the requirements of ASC 606. The ultimate impactunderlying principle of the new standard has not yet been determined.
On April 7, 2015,is to recognize revenue to depict the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputationtransfer of Interest (Subtopic 835-30): Simplifyinggoods or services to customers at the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs relatedamount expected to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes.collected. The new guidance resulted in an adjustment tostandard also requires enhanced disclosures regarding the presentationnature, amount, timing, and uncertainty of debt issuance costs as an offset torevenue and the related debt balances in long-term debt totaling $39 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows or financial conditionarising from contracts with customers.
Most of the Company. See Note 10Company's revenue, including energy provided to the financial statements for disclosures impacted by ASU 2015-03.
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidancecustomers, is from tariff offerings that provide electricity without a defined contractual term, as of December 31, 2015 and applied itswell as longer-term contractual commitments, including PPAs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
provisions retrospectivelyThe Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to eachbe accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirementyear reported results are not restated; however, a cumulative-effect adjustment to categorize within the fair value hierarchy all investments for which fair valueretained earnings at January 1, 2018 is measured using the net asset value per share practical expedient.recorded. In addition, the amendments remove the requirement to make certainquarterly disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to thewill include comparative information on 2018 financial statement line items under current presentation.guidance. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 to the financial statements for disclosures impacted by ASU 2015-07.ASC 606 did not result in a cumulative-effect adjustment.
Leases
On November 20, 2015,In February 2016, the FASB issued ASU No. 2015-17,2016-02, Income TaxesLeases (Topic 740): Balance Sheet Classification of Deferred Taxes 842)( (ASU 2016-02). ASU 2015-17), which simplifies2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of deferred income taxes.expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and2016-02 is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted,2018 and the Company elected to earlywill adopt the guidance asnew standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of December 31, 2015its leases. In terms of rental charges and applied its provisions retrospectivelyduration of contracts, the most significant leases relate to each prior period presented for comparative purposes. Priorcellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2015-17, all deferred income tax assets and liabilities were required2016-02 is expected to be separated into current and non-current amounts. The new guidance resulted inhave a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxes in the Company’s December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have ansignificant impact on the resultsCompany's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of operations, cash flows,Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or financial conditionitems as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the Company. See Note 5service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial statementsand non-financial hedging strategies eligible for disclosures impacted byhedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2015-17.2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2015.2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
investing activities include investments to meet projected long-term demand requirements, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 20162018 through 2018,2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debtexternal securities issuances, preferredborrowings from financial institutions, or equity contributions from Southern Company. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and preference stock issuances, or parent companyfor other working capital contributions.needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds decreasedincreased in value as of December 31, 20152017 as compared to December 31, 2014.2016. No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated during 2016.2018. The Company's funding obligations for the nuclear decommissioning trust fund are based on the most recent site study, and the next study is expected to be conducted in 2018. See Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities totaled $2.1$1.8 billion for 2015, an increase2017, a decrease of $433$112 million as compared to 2014.2016. The increasedecrease in cash provided from operating activities was primarily due to the timing of income tax payments in 2017 and the receipt of income tax refunds associated within 2016 as a result of bonus depreciation, collection of fuel cost recovery revenues, partially offset by the timing of payment of accounts payable.voluntary contribution to the qualified pension plan in 2016. Net cash provided from operating activities totaled $1.7$1.9 billion for 2014,2016, a decrease of $205$193 million as compared to 2013.2015. The decrease in cash provided from operating activities was primarily due to an increase in income tax paymentsthe collection of fuel cost recovery revenues and the timing of fossil fuel stock purchases,voluntary contribution to the qualified pension plan, partially offset by the timing of payment of accounts payable.income tax payments and refunds associated with bonus depreciation.
Net cash used for investing activities totaled $1.9 billion for 2017, $1.4 billion for 2016, and $1.5 billion for 2015, $1.6 billion for 2014, and $1.1 billion for 2013. In 2015, these2015. These activities were primarily related to gross property additions for environmental, distribution, steam generation, and transmission assets. In 2014, these activities were primarily related to gross property additions for environmental, distribution, transmission, steam generation, and nuclear fuel assets. In 2013, these activities were primarily related to gross property additions for steam generation, distribution, and transmission assets.
Net cash provided from financing activities totaled $163 million in 2017 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and maturities of long-term debt. Net cash used for financing activities totaled $733$285 million in 20152016 primarily due to the payment of common stock dividends and redemptionsa redemption of securities,long-term debt, partially offset by issuances of long-term debt. Net cash used for financing activities totaled $164 million in 2014 primarily due to the payment of common stock dividendsdebt and issuances and redemptions of securities.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
additional capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for 20152017 included an increaseincreases of $1.3 billion in property, plant, and equipment primarily due to additions to steam generation, environmental, distribution and transmission facilities including $619 millionand environmental and steam generation assets and $1.1 billion in AROs associated with the CCR Rule.long-term debt. Other significant changes includeincluded an increase of $384 million$2.0 billion in deferred credits related to income taxes and decreases of $1.9 billion in accumulated deferred income taxes primarily as a result of bonus depreciationdue to the change in tax rate resulting from Tax Reform Legislation and an increase of $263 million$0.6 billion in long term debt, including debtsecurities due within one year, primarily due to the issuance of additional senior notes.year. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning"FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The Company's ratio of common equity to total capitalization includingplus short-term debt was 45.6%46.3% and 44.2%46.2% at December 31, 20152017 and 2014,2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds to meet its future capital needs throughfrom sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.
Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
The Company's current liabilities sometimes exceed current assets because of the Company'slong-term debt due within one yearmaturities and the periodic use of short-term debt as a funding source, primarily to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs, which can fluctuate significantly due to the seasonality of the business.needs.
At December 31, 2015,2017, the Company had approximately $194$544 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 20152017 were as follows:
| | Expires | Expires | | | | | | Due Within One Year | Expires | | | | | | Expires Within One Year |
2016 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out | |
2018 | | 2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
(in millions) | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) |
$ | 40 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,340 |
| | $ | 1,340 |
| | $ | — |
| | $ | 40 |
| 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In May 2017 and September 2017, the Company amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
Most of these bank credit arrangements, as well as the Company's term loan arrangements, contain covenants that limit debt levels and contain cross accelerationcross-acceleration provisions to other indebtedness (including guarantee obligations) of the Company. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. TheAt December 31, 2017, the Company is currentlywas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper borrowings. Asprograms. The amount of December 31, 2015, the Company had $810 million of outstanding variable rate pollution control revenue bonds outstanding requiring liquidity support.support was $854 million as of December 31, 2017. In addition, at December 31, 2015,2017, the Company had $80$120 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
In addition, theThe Company also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. The Company may meet short-term cash needs through its commercial paper
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
program. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2015: | | | | | | | | | |
Commercial paper | $ | — |
| | — | % | | $ | 14 |
| | 0.2 | % | | $ | 100 |
|
December 31, 2014: | | | | | | | | | |
Commercial paper | $ | — |
| | — | % | | $ | 13 |
| | 0.2 | % | | $ | 300 |
|
December 31, 2013: | | | | | | | | | |
Commercial paper | $ | — |
| | — | % | | $ | 11 |
| | 0.2 | % | | $ | 90 |
|
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 3 |
| | 3.7 | % | | $ | 25 |
| | 1.3 | % | | $ | 223 |
|
December 31, 2016 | $ | — |
| | — | % | | $ | 16 |
| | 0.6 | % | | $ | 200 |
|
December 31, 2015 | $ | — |
| | — | % | | $ | 14 |
| | 0.2 | % | | $ | 100 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month12-month periods ended December 31, 2015, 2014,2017, 2016, and 2013.2015. |
The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Financing Activities
In March 2015, the Company issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including the Company's continuous construction program.
In April 2015, the Company purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. The Company reoffered these bonds to the public in May 2015.
Also in April 2015, the Company issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used in May 2015 to redeem 6.48 million shares ($162 million aggregate stated capital) of the Company's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of the Company's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of the Company's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including the Company's continuous construction program.
In June 2015, $18.7 million aggregate principal amount of the Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994, $6.15 million aggregate principal amount of the Industrial Development Board of the City of Gadsden, Pollution Control Revenue Bonds (Alabama Power Company Project), Series 1994, and $28.85 million aggregate principal amount of the Industrial Development Board of the Town of Parrish, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994A were repaid at maturity.
In October 2015, the Company repaid at maturity $400 million aggregate principal amount of its Series 2012B 0.550% Senior Notes due October 15, 2015.
Subsequent to December 31, 2015, the Company issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Company'sFinancing Activities
In February 2017, the Company repaid at maturity $200 million aggregate principal amount of Series FF 5.20%2007A 5.55% Senior Notes.
In March 2017, the Company issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due January 15, 2016March 30, 2022. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
In September 2017, the Company issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including the Company's continuous construction program.
In October 2017, the Company repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes.
In November 2017, the Company issued $550 million aggregate principal amount of Series 2017B 3.70% Senior Notes due December 1, 2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
TheAt December 31, 2017, the Company doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 20152017 were as follows:
| | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| (in millions) | (in millions) |
At BBB and/or Baa2 | $ | 1 |
| $ | 1 |
|
At BBB- and/or Baa3 | $ | 2 |
| $ | 2 |
|
Below BBB- and/or Baa3 | $ | 350 |
| $ | 323 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneeither the Company or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On August 17, 2015,March 24, 2017, S&P downgraded therevised its consolidated long-term issuercredit rating ofoutlook for Southern Company and its subsidiaries (including the Company) to A- from A. S&P revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative followingnegative.
On January 19, 2018, Moody's revised its rating outlook for the announcement ofCompany from stable to negative.
While it is unclear how the proposed merger of a wholly-owned direct subsidiary ofcredit rating agencies and regulatory authorities may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company with and into AGL Resources Inc.its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure at December 31, 2017 was 2.3%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $11 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 20152017 when compared to the year ended December 31, 2014.2016.
In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of the Company's natural gas budget for that year.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
| | | 2015 Changes | | 2014 Changes | 2017 Changes | | 2016 Changes |
| Fair Value | Fair Value |
| (in millions) | (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (52 | ) | | $ | (1 | ) | $ | 12 |
| | $ | (54 | ) |
Contracts realized or settled | 41 |
| | (7 | ) | (1 | ) | | 39 |
|
Current period changes(*) | (43 | ) | | (44 | ) | (17 | ) | | 27 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (54 | ) | | $ | (52 | ) | $ | (6 | ) | | $ | 12 |
|
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| mmBtu Volume | mmBtu Volume |
| (in millions) | (in millions) |
Commodity – Natural gas swaps | 44 |
| | 54 |
| 64 |
| | 68 |
|
Commodity – Natural gas options | 6 |
| | 2 |
| 5 |
| | 6 |
|
Total hedge volume | 50 |
| | 56 |
| 69 |
| | 74 |
|
The weighted average swap contract cost above market prices was approximately $1.13$0.08 per mmBtu as of December 31, 20152017 and $0.89below market prices was approximately $0.14 per mmBtu as of December 31, 2014.2016. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. The majoritySubstantially all of the natural gas hedge gains and losses are recovered through the Company's retail energy cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
At December 31, 20152017 and 2014,2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2.2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are allprimarily Level 2 of the fair value hierarchy, at December 31, 20152017 were as follows:
| | | | | Fair Value Measurements | | | Fair Value Measurements |
| | | December 31, 2015 | | | December 31, 2017 |
| Total | | Maturity | Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 | Fair Value | | Year 1 | | Years 2&3 |
| (in millions) | (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (54 | ) | | (39 | ) | | (15 | ) | 6 |
| | 4 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (54 | ) | | $ | (39 | ) | | $ | (15 | ) | $ | 6 |
| | $ | 4 |
| | $ | 2 |
|
The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2015 Annual Report
grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to total $1.3$2.2 billion per year for 2016, 2017,2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and 2018.$1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statuteslaws and regulations included in these amounts are $0.3 billion per year$581 million for 2016, 2017,2018, $110 million for 2019, $163 million for 2020, $258 million for 2021, and 2018.$268 million for 2022. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA's final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-firedfossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $20 million, $20 million, and $66$0.3 million for the years 2016, 2017,2018, $111 million for 2019, $90 million for 2020, $94 million for 2021, and 2018 respectively.$96 million for 2022. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
As a result of NRC requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other postretirement benefit plans, preferred and preference stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
| | | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total | 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) | (in millions) |
Long-term debt(a) — | | | | | | | | | | | | | | | | | | |
Principal | $ | 200 |
| | $ | 561 |
| | $ | 450 |
| | $ | 5,692 |
| | $ | 6,903 |
| $ | — |
| | $ | 450 |
| | $ | 1,060 |
| | $ | 6,176 |
| | $ | 7,686 |
|
Interest | 275 |
| | 500 |
| | 461 |
| | 3,706 |
| | 4,942 |
| 304 |
| | 598 |
| | 561 |
| | 4,408 |
| | 5,871 |
|
Preferred and preference stock dividends(b) | 17 |
| | 34 |
| | 34 |
| | — |
| | 85 |
| |
Preferred stock dividends(b) | | 15 |
| | 29 |
| | 29 |
| | — |
| | 73 |
|
Financial derivative obligations(c) | 54 |
| | 16 |
| | — |
| | — |
| | 70 |
| 6 |
| | 4 |
| | — |
| | — |
| | 10 |
|
Operating leases(d) | 19 |
| | 22 |
| | 18 |
| | 13 |
| | 72 |
| 21 |
| | 40 |
| | 24 |
| | 20 |
| | 105 |
|
Capital Lease | — |
| | 1 |
| | 1 |
| | 3 |
| | 5 |
| 1 |
| | 1 |
| | 1 |
| | 2 |
| | 5 |
|
Purchase commitments — | | | | | | | | | | | | | | | | | | |
Capital(e) | 1,210 |
| | 2,370 |
| | — |
| | — |
| | 3,580 |
| 2,053 |
| | 2,972 |
| | 2,914 |
| | — |
| | 7,939 |
|
Fuel(f) | 1,108 |
| | 1,638 |
| | 886 |
| | 261 |
| | 3,893 |
| 974 |
| | 1,197 |
| | 459 |
| | 238 |
| | 2,868 |
|
Purchased power(g) | 78 |
| | 167 |
| | 182 |
| | 803 |
| | 1,230 |
| 78 |
| | 171 |
| | 186 |
| | 606 |
| | 1,041 |
|
Other(h) | 40 |
| | 83 |
| | 67 |
| | 335 |
| | 525 |
| 47 |
| | 73 |
| | 59 |
| | 313 |
| | 492 |
|
Pension and other postretirement benefit plans(i) | 20 |
| | 38 |
| | — |
| | — |
| | 58 |
| 19 |
| | 36 |
| | — |
| | — |
| | 55 |
|
Total | $ | 3,021 |
| | $ | 5,430 |
| | $ | 2,099 |
| | $ | 10,813 |
| | $ | 21,363 |
| $ | 3,518 |
| | $ | 5,571 |
| | $ | 5,293 |
| | $ | 11,763 |
| | $ | 26,145 |
|
| |
(a) | All amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2016,December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Preferred and preference stock dodoes not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and are included in purchased power. |
| |
(e) | The Company provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2015, significant2017, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" herein for additional information. |
| |
(f) | Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(g) | Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. Amounts are related to the Company's certificated PPAs which include MWs purchased from gas-fired and wind-powered facilities. |
| |
(h) | Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retailregulated rates, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of changing fuel sources, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;
investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Alabama Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Retail revenues | $ | 5,234 |
| | $ | 5,249 |
| | $ | 4,952 |
| $ | 5,458 |
| | $ | 5,322 |
| | $ | 5,234 |
|
Wholesale revenues, non-affiliates | 241 |
| | 281 |
| | 248 |
| 276 |
| | 283 |
| | 241 |
|
Wholesale revenues, affiliates | 84 |
| | 189 |
| | 212 |
| 97 |
| | 69 |
| | 84 |
|
Other revenues | 209 |
| | 223 |
| | 206 |
| 208 |
| | 215 |
| | 209 |
|
Total operating revenues | 5,768 |
| | 5,942 |
| | 5,618 |
| 6,039 |
| | 5,889 |
| | 5,768 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 1,342 |
| | 1,605 |
| | 1,631 |
| 1,225 |
| | 1,297 |
| | 1,342 |
|
Purchased power, non-affiliates | 171 |
| | 185 |
| | 100 |
| 170 |
| | 166 |
| | 171 |
|
Purchased power, affiliates | 180 |
| | 200 |
| | 129 |
| 158 |
| | 168 |
| | 180 |
|
Other operations and maintenance | 1,501 |
| | 1,468 |
| | 1,289 |
| 1,652 |
| | 1,510 |
| | 1,501 |
|
Depreciation and amortization | 643 |
| | 603 |
| | 645 |
| 736 |
| | 703 |
| | 643 |
|
Taxes other than income taxes | 368 |
| | 356 |
| | 348 |
| 384 |
| | 380 |
| | 368 |
|
Total operating expenses | 4,205 |
| | 4,417 |
| | 4,142 |
| 4,325 |
| | 4,224 |
| | 4,205 |
|
Operating Income | 1,563 |
| | 1,525 |
| | 1,476 |
| 1,714 |
| | 1,665 |
| | 1,563 |
|
Other Income and (Expense): | | | | | | | | | | |
Allowance for equity funds used during construction | 60 |
| | 49 |
| | 32 |
| 39 |
| | 28 |
| | 60 |
|
Interest income | 15 |
| | 15 |
| | 16 |
| |
Interest expense, net of amounts capitalized | (274 | ) | | (255 | ) | | (259 | ) | (305 | ) | | (302 | ) | | (274 | ) |
Other income (expense), net | (47 | ) | | (22 | ) | | (36 | ) | (14 | ) | | (21 | ) | | (32 | ) |
Total other income and (expense) | (246 | ) | | (213 | ) | | (247 | ) | (280 | ) | | (295 | ) | | (246 | ) |
Earnings Before Income Taxes | 1,317 |
| | 1,312 |
| | 1,229 |
| 1,434 |
| | 1,370 |
| | 1,317 |
|
Income taxes | 506 |
| | 512 |
| | 478 |
| 568 |
| | 531 |
| | 506 |
|
Net Income | 811 |
| | 800 |
| | 751 |
| 866 |
| | 839 |
| | 811 |
|
Dividends on Preferred and Preference Stock | 26 |
| | 39 |
| | 39 |
| 18 |
| | 17 |
| | 26 |
|
Net Income After Dividends on Preferred and Preference Stock | $ | 785 |
| | $ | 761 |
| | $ | 712 |
| $ | 848 |
| | $ | 822 |
| | $ | 785 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Alabama Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Net Income | $ | 811 |
| | $ | 800 |
| | $ | 751 |
| $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Other comprehensive income (loss): | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $(3), $(3), and $-, respectively | (5 | ) | | (5 | ) | | — |
| |
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 2 |
| | 2 |
| | 1 |
| |
Changes in fair value, net of tax of $(1), $(1), and $(3), respectively | | 1 |
| | (2 | ) | | (5 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $1, respectively | | 3 |
| | 4 |
| | 2 |
|
Total other comprehensive income (loss) | (3 | ) | | (3 | ) | | 1 |
| 4 |
| | 2 |
| | (3 | ) |
Comprehensive Income | $ | 808 |
| | $ | 797 |
| | $ | 752 |
| $ | 870 |
| | $ | 841 |
| | $ | 808 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Alabama Power Company 20152017 Annual Report | | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Activities: | | | | | | | | | | |
Net income | $ | 811 |
| | $ | 800 |
| | $ | 751 |
| $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization, total | 780 |
| | 724 |
| | 816 |
| 888 |
| | 844 |
| | 780 |
|
Deferred income taxes | 388 |
| | 270 |
| | 198 |
| 409 |
| | 407 |
| | 388 |
|
Allowance for equity funds used during construction | (60 | ) | | (49 | ) | | (32 | ) | (39 | ) | | (28 | ) | | (60 | ) |
Pension, postretirement, and other employee benefits | 20 |
| | (61 | ) | | 9 |
| |
Stock based compensation expense | 15 |
| | 11 |
| | 10 |
| |
Pension and postretirement funding | | (2 | ) | | (133 | ) | | — |
|
Other, net | (20 | ) | | 17 |
| | (38 | ) | (14 | ) | | (102 | ) | | 15 |
|
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | (160 | ) | | (58 | ) | | 2 |
| (168 | ) | | 94 |
| | (160 | ) |
-Fossil fuel stock | 28 |
| | 61 |
| | 146 |
| |
-Materials and supplies | 15 |
| | (17 | ) | | 19 |
| |
-Other current assets | (3 | ) | | (11 | ) | | 5 |
| (16 | ) | | 1 |
| | 40 |
|
-Accounts payable | 3 |
| | 157 |
| | 35 |
| 71 |
| | 73 |
| | 3 |
|
-Accrued taxes | 138 |
| | (199 | ) | | (23 | ) | (84 | ) | | 93 |
| | 138 |
|
-Accrued compensation | (16 | ) | | 50 |
| | (23 | ) | |
-Retail fuel cost over recovery | 191 |
| | 5 |
| | 42 |
| (76 | ) | | (162 | ) | | 191 |
|
-Other current liabilities | 12 |
| | 9 |
| | (3 | ) | 2 |
| | 23 |
| | (4 | ) |
Net cash provided from operating activities | 2,142 |
| | 1,709 |
| | 1,914 |
| 1,837 |
| | 1,949 |
| | 2,142 |
|
Investing Activities: | | | | | | | | | | |
Property additions | (1,367 | ) | | (1,457 | ) | | (1,107 | ) | (1,882 | ) | | (1,272 | ) | | (1,367 | ) |
Nuclear decommissioning trust fund purchases | (439 | ) | | (245 | ) | | (280 | ) | (237 | ) | | (352 | ) | | (439 | ) |
Nuclear decommissioning trust fund sales | 438 |
| | 244 |
| | 279 |
| 237 |
| | 351 |
| | 438 |
|
Cost of removal net of salvage | (71 | ) | | (77 | ) | | (47 | ) | (112 | ) | | (94 | ) | | (71 | ) |
Change in construction payables | (15 | ) | | (10 | ) | | (13 | ) | 161 |
| | (37 | ) | | (15 | ) |
Other investing activities | (34 | ) | | (22 | ) | | 26 |
| (43 | ) | | (34 | ) | | (34 | ) |
Net cash used for investing activities | (1,488 | ) | | (1,567 | ) | | (1,142 | ) | (1,876 | ) | | (1,438 | ) | | (1,488 | ) |
Financing Activities: | | | | | | | | | | |
Increase in notes payable, net | | 3 |
| | — |
| | — |
|
Proceeds — | | | | | | | | | | |
Senior notes | | 1,100 |
| | 400 |
| | 975 |
|
Preferred stock | | 250 |
| | — |
| | — |
|
Pollution control revenue bonds | | — |
| | — |
| | 80 |
|
Other long-term debt | | — |
| | 45 |
| | — |
|
Capital contributions from parent company | 22 |
| | 28 |
| | 24 |
| 361 |
| | 260 |
| | 22 |
|
Pollution control revenue bonds | 80 |
| | 254 |
| | — |
| |
Senior notes issuances | 975 |
| | 400 |
| | 300 |
| |
Redemptions and repurchases — | | | | | | | | | | |
Senior notes | | (525 | ) | | (200 | ) | | (650 | ) |
Preferred and preference stock | (412 | ) | | — |
| | — |
| (238 | ) | | — |
| | (412 | ) |
Pollution control revenue bonds | (134 | ) | | (254 | ) | | — |
| (36 | ) | | — |
| | (134 | ) |
Senior notes | (650 | ) | | — |
| | (250 | ) | |
Payment of preferred and preference stock dividends | (31 | ) | | (39 | ) | | (39 | ) | |
Payment of common stock dividends | (571 | ) | | (550 | ) | | (644 | ) | (714 | ) | | (765 | ) | | (571 | ) |
Other financing activities | (12 | ) | | (3 | ) | | (5 | ) | (38 | ) | | (25 | ) | | (43 | ) |
Net cash used for financing activities | (733 | ) | | (164 | ) | | (614 | ) | |
Net cash provided from (used for) financing activities | | 163 |
| | (285 | ) | | (733 | ) |
Net Change in Cash and Cash Equivalents | (79 | ) | | (22 | ) | | 158 |
| 124 |
| | 226 |
| | (79 | ) |
Cash and Cash Equivalents at Beginning of Year | 273 |
| | 295 |
| | 137 |
| 420 |
| | 194 |
| | 273 |
|
Cash and Cash Equivalents at End of Year | $ | 194 |
| | $ | 273 |
| | $ | 295 |
| $ | 544 |
| | $ | 420 |
| | $ | 194 |
|
Supplemental Cash Flow Information: | | | | | | | | | | |
Cash paid during the period for — | | | | | | |
Interest (net of $22, $18, and $11 capitalized, respectively) | $ | 250 |
| | $ | 231 |
| | $ | 243 |
| |
Cash paid (received) during the period for — | | | | | | |
Interest (net of $15, $11, and $22 capitalized, respectively) | | $ | 285 |
| | $ | 277 |
| | $ | 250 |
|
Income taxes (net of refunds) | 121 |
| | 436 |
| | 296 |
| 236 |
| | (108 | ) | | 121 |
|
Noncash transactions — accrued property additions at year-end | 121 |
| | 8 |
| | 18 |
| |
Noncash transactions — Accrued property additions at year-end | | 245 |
| | 84 |
| | 121 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Alabama Power Company 20152017 Annual Report
| | Assets | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 194 |
| | $ | 273 |
| $ | 544 |
| | $ | 420 |
|
Receivables — | | | | | | |
Customer accounts receivable | 332 |
| | 345 |
| 355 |
| | 348 |
|
Unbilled revenues | 119 |
| | 138 |
| 162 |
| | 146 |
|
Under recovered regulatory clause revenues | 43 |
| | 74 |
| |
Affiliated | | 43 |
| | 40 |
|
Other accounts and notes receivable | 20 |
| | 23 |
| 55 |
| | 27 |
|
Affiliated companies | 50 |
| | 37 |
| |
Accumulated provision for uncollectible accounts | (10 | ) | | (9 | ) | (9 | ) | | (10 | ) |
Income taxes receivable, current | 142 |
| | — |
| |
Fossil fuel stock, at average cost | 239 |
| | 268 |
| |
Materials and supplies, at average cost | 398 |
| | 406 |
| |
Vacation pay | 66 |
| | 65 |
| |
Prepaid expenses | 83 |
| | 224 |
| |
Fossil fuel stock | | 184 |
| | 205 |
|
Materials and supplies | | 458 |
| | 435 |
|
Other regulatory assets, current | 115 |
| | 84 |
| 124 |
| | 149 |
|
Other current assets | 10 |
| | 6 |
| 90 |
| | 45 |
|
Total current assets | 1,801 |
| | 1,934 |
| 2,006 |
| | 1,805 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 24,750 |
| | 23,080 |
| 27,326 |
| | 26,031 |
|
Less accumulated provision for depreciation | 8,736 |
| | 8,522 |
| |
Less: Accumulated provision for depreciation | | 9,563 |
| | 9,112 |
|
Plant in service, net of depreciation | 16,014 |
| | 14,558 |
| 17,763 |
| | 16,919 |
|
Nuclear fuel, at amortized cost | 363 |
| | 348 |
| 339 |
| | 336 |
|
Construction work in progress | 801 |
| | 1,006 |
| 908 |
| | 491 |
|
Total property, plant, and equipment | 17,178 |
| | 15,912 |
| 19,010 |
| | 17,746 |
|
Other Property and Investments: | | | | | | |
Equity investments in unconsolidated subsidiaries | 71 |
| | 66 |
| 67 |
| | 66 |
|
Nuclear decommissioning trusts, at fair value | 737 |
| | 756 |
| 903 |
| | 792 |
|
Miscellaneous property and investments | 96 |
| | 84 |
| 124 |
| | 112 |
|
Total other property and investments | 904 |
| | 906 |
| 1,094 |
| | 970 |
|
Deferred Charges and Other Assets: | | | | | | |
Deferred charges related to income taxes | 522 |
| | 525 |
| 239 |
| | 525 |
|
Deferred under recovered regulatory clause revenues | 99 |
| | 31 |
| 54 |
| | 150 |
|
Other regulatory assets, deferred | 1,114 |
| | 1,063 |
| 1,272 |
| | 1,157 |
|
Other deferred charges and assets | 103 |
| | 122 |
| 189 |
| | 163 |
|
Total deferred charges and other assets | 1,838 |
| | 1,741 |
| 1,754 |
| | 1,995 |
|
Total Assets | $ | 21,721 |
| | $ | 20,493 |
| $ | 23,864 |
| | $ | 22,516 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Alabama Power Company 20152017 Annual Report
| | Liabilities and Stockholder's Equity | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Liabilities: | | | | | | |
Securities due within one year | $ | 200 |
| | $ | 454 |
| $ | — |
| | $ | 561 |
|
Accounts payable — | | | | | | |
Affiliated | 278 |
| | 248 |
| 327 |
| | 297 |
|
Other | 410 |
| | 443 |
| 585 |
| | 433 |
|
Customer deposits | 88 |
| | 87 |
| 92 |
| | 88 |
|
Accrued taxes | 38 |
| | 37 |
| |
Accrued taxes — | | | | |
Accrued income taxes | | 9 |
| | 45 |
|
Other accrued taxes | | 45 |
| | 42 |
|
Accrued interest | 73 |
| | 66 |
| 77 |
| | 78 |
|
Accrued vacation pay | 55 |
| | 54 |
| |
Accrued compensation | 119 |
| | 131 |
| 205 |
| | 193 |
|
Liabilities from risk management activities | 55 |
| | 40 |
| |
Other regulatory liabilities, current | 240 |
| | 2 |
| 1 |
| | 85 |
|
Other current liabilities | 39 |
| | 40 |
| 59 |
| | 76 |
|
Total current liabilities | 1,595 |
| | 1,602 |
| 1,400 |
| | 1,898 |
|
Long-Term Debt (See accompanying statements) | 6,654 |
| | 6,137 |
| 7,628 |
| | 6,535 |
|
Deferred Credits and Other Liabilities: | | | | | | |
Accumulated deferred income taxes | 4,241 |
| | 3,857 |
| 2,760 |
| | 4,654 |
|
Deferred credits related to income taxes | 70 |
| | 72 |
| 2,082 |
| | 65 |
|
Accumulated deferred investment tax credits | 118 |
| | 125 |
| |
Accumulated deferred ITCs | | 112 |
| | 110 |
|
Employee benefit obligations | 388 |
| | 326 |
| 304 |
| | 300 |
|
Asset retirement obligations | 1,448 |
| | 829 |
| 1,702 |
| | 1,503 |
|
Other cost of removal obligations | 722 |
| | 744 |
| 609 |
| | 684 |
|
Other regulatory liabilities, deferred | 136 |
| | 239 |
| 84 |
| | 100 |
|
Deferred over recovered regulatory clause revenues | — |
| | 47 |
| |
Other deferred credits and liabilities | 76 |
| | 78 |
| 63 |
| | 63 |
|
Total deferred credits and other liabilities | 7,199 |
| | 6,317 |
| 7,716 |
| | 7,479 |
|
Total Liabilities | 15,448 |
| | 14,056 |
| 16,744 |
| | 15,912 |
|
Redeemable Preferred Stock (See accompanying statements) | 85 |
| | 342 |
| 291 |
| | 85 |
|
Preference Stock (See accompanying statements) | 196 |
| | 343 |
| — |
| | 196 |
|
Common Stockholder's Equity (See accompanying statements) | 5,992 |
| | 5,752 |
| 6,829 |
| | 6,323 |
|
Total Liabilities and Stockholder's Equity | $ | 21,721 |
| | $ | 20,493 |
| $ | 23,864 |
| | $ | 22,516 |
|
Commitments and Contingent Matters (See notes) |
| |
|
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 20152017 and 20142016
Alabama Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) | (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | | | | | | | | |
Variable rate (3.43% at 1/1/16) due 2042 | $ | 206 |
| | $ | 206 |
| | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | | $ | 206 |
| | $ | 206 |
| | | | |
Long-term notes payable — | | | | | | | | | | | | | | |
0.55% due 2015 | — |
| | 400 |
| | | | | |
5.20% due 2016 | 200 |
| | 200 |
| | | | | |
5.50% to 5.55% due 2017 | 525 |
| | 525 |
| | | | | — |
| | 525 |
| | | | |
5.125% due 2019 | 200 |
| | 200 |
| | | | | 200 |
| | 200 |
| | | | |
3.375% due 2020 | 250 |
| | 250 |
| | | | | 250 |
| | 250 |
| | | | |
2.80% to 6.125% due 2021-2045 | 4,425 |
| | 3,700 |
| | | | | |
2.38% to 3.95% due 2021 | | 220 |
| | 220 |
| | | | |
2.45% to 5.875% due 2022 | | 750 |
| | 200 |
| | | | |
2.80% to 6.125% due 2023-2047 | | 4,975 |
| | 4,425 |
| | | | |
Variable rates (2.55% to 2.786% at 12/31/17) due 2021 | | 25 |
| | 25 |
| | | | |
Total long-term notes payable | 5,600 |
| | 5,275 |
| | | | | 6,420 |
| | 5,845 |
| | | | |
Other long-term debt — | | | | | | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | | | | | | |
0.28% to 5.00% due 2034 | 287 |
| | 367 |
| | | | | |
Variable rate (0.03% at 1/1/15) due 2015 | — |
| | 54 |
| | | | | |
Variable rates (0.05% to 0.06% at 1/1/16) due 2017 | 36 |
| | 36 |
| | | | | |
Variable rates (0.01% to 0.09% at 1/1/16) due 2021-2038 | 774 |
| | 694 |
| | | | | |
1.625% to 1.85% due 2034 | | 207 |
| | 207 |
| | | | |
Variable rates (0.77% to 0.79% at 1/1/17) due 2017 | | — |
| | 36 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | | 65 |
| | 65 |
| | | | |
Variable rates (1.70% to 1.87% at 12/31/17) due 2024-2038 | | 788 |
| | 788 |
| | | | |
Total other long-term debt | 1,097 |
| | 1,151 |
| | | | | 1,060 |
| | 1,096 |
| | | | |
Capitalized lease obligations | 5 |
| | 5 |
| | | | | 4 |
| | 4 |
| | | | |
Unamortized debt premium (discount), net | (9 | ) | | (7 | ) | | | | | (11 | ) | | (9 | ) | | | | |
Unamortized debt issuance expense | (45 | ) | | (39 | ) | | | | | (51 | ) | | (46 | ) | | | | |
Total long-term debt (annual interest requirement — $275 million) | 6,854 |
| | 6,591 |
| | | | | |
Total long-term debt (annual interest requirement — $305 million) | | 7,628 |
| | 7,096 |
| | | | |
Less amount due within one year | 200 |
| | 454 |
| | | | | — |
| | 561 |
| | | | |
Long-term debt excluding amount due within one year | 6,654 |
| | 6,137 |
| | 51.4 | % | | 48.8 | % | 7,628 |
| | 6,535 |
| | 51.7 | % | | 49.7 | % |
Redeemable Preferred Stock: | | | | | | | | | | | | | | |
Cumulative redeemable preferred stock | | | | | | | | | | | | | | |
$100 par or stated value — 4.20% to 4.92% | | | | | | | | | | | | | | |
Authorized — 3,850,000 shares | | | | | | | | | | | | | | |
Outstanding — 475,115 shares | 48 |
| | 48 |
| | | | | 48 |
| | 48 |
| | | | |
$1 par value — | | | | | | | | | | | | | | |
Authorized — 27,500,000 shares | | | | | | | | | | | | | | |
Outstanding — $25 stated value | | | | | | | | |
— 2015: 5.83% — 1,520,000 shares | | | | | | | | |
— 2014: 5.20% to 5.83% — 12,000,000 shares | | | | | | | | |
(annual dividend requirement — $4 million) | 37 |
| | 294 |
| | | | | |
Outstanding — 2017: 5.00% — 10,000,000 shares: $25 stated value | | | | | | | | |
— 2016: 5.83% — 1,520,000 shares: $25 stated value | | | | | | | | |
(annual dividend requirement — $15 million) | | 243 |
| | 37 |
| | | | |
Total redeemable preferred stock | 85 |
| | 342 |
| | 0.7 |
| | 2.7 |
| 291 |
| | 85 |
| | 2.0 |
| | 0.7 |
|
Preference Stock: | | | | | | | | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | | | | | | | | |
Outstanding — $1 par value — $25 stated value | | | | | | | | |
— 2015: 6.45% to 6.50% — 8,000,000 shares (non-cumulative) | | | | | | | | |
— 2014: 5.63% to 6.50% — 14,000,000 shares (non-cumulative) | | | | | | | | |
(annual dividend requirement — $13 million) | 196 |
| | 343 |
| | 1.5 | | 2.7 | |
Outstanding — 2017: no shares | | | | | | | | |
— 2016: 8,000,000 shares (non-cumulative): $25 stated value | | — |
| | 196 |
| | — | | 1.5 |
Common Stockholder's Equity: | | | | | | | | | | | | | | |
Common stock, par value $40 per share — | | | | | | | | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | | | | | | | | |
Outstanding — 30,537,500 shares | 1,222 |
| | 1,222 |
| | | | | 1,222 |
| | 1,222 |
| | | | |
Paid-in capital | 2,341 |
| | 2,304 |
| | | | | 2,986 |
| | 2,613 |
| | | | |
Retained earnings | 2,461 |
| | 2,255 |
| | | | | 2,647 |
| | 2,518 |
| | | | |
Accumulated other comprehensive loss | (32 | ) | | (29 | ) | | | | | (26 | ) | | (30 | ) | | | | |
Total common stockholder's equity | 5,992 |
| | 5,752 |
| | 46.4 |
| | 45.8 |
| 6,829 |
| | 6,323 |
| | 46.3 |
| | 48.1 |
|
Total Capitalization | $ | 12,927 |
| | $ | 12,574 |
| | 100.0 | % | | 100.0 | % | $ | 14,748 |
| | $ | 13,139 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITYRate NDR
ForBased on an order from the Years Ended December 31, 2015, 2014, and 2013
Alabama PSC, Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) |
Balance at December 31, 2012 | 31 |
| | $ | 1,222 |
| | $ | 2,227 |
| | $ | 1,976 |
| | $ | (27 | ) | | $ | 5,398 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 712 |
| | — |
| | 712 |
|
Capital contributions from parent company | — |
| | — |
| | 35 |
| | — |
| | — |
| | 35 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (644 | ) | | — |
| | (644 | ) |
Balance at December 31, 2013 | 31 |
| | 1,222 |
| | 2,262 |
| | 2,044 |
| | (26 | ) | | 5,502 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 761 |
| | — |
| | 761 |
|
Capital contributions from parent company | — |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (3 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (550 | ) | | — |
| | (550 | ) |
Balance at December 31, 2014 | 31 |
| | 1,222 |
| | 2,304 |
| | 2,255 |
| | (29 | ) | | 5,752 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 785 |
| | — |
| | 785 |
|
Capital contributions from parent company | — |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (3 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (571 | ) | | — |
| | (571 | ) |
Other | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
Balance at December 31, 2015 | 31 |
| | $ | 1,222 |
| | $ | 2,341 |
| | $ | 2,461 |
| | $ | (32 | ) | | $ | 5,992 |
|
maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The accompanying notes areorder approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an integralon-going part of these financial statements.customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both
NOTES TO FINANCIAL STATEMENTS(continued)
Alabama PowerSouthern Company 2015and Subsidiary Companies 2017 Annual Report
components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.
Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements.
Georgia Power
Rate Plans
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.
In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million; (3) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.
IndexNOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the Notesnext fuel case if the under recovered fuel balance exceeds $200 million.
Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.
Georgia Power's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other regulatory liabilities, current.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory asset for storm damage totaled approximately $260 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements.
At December 31, 2017 and December 31, 2016, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million and $206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively.
Gulf Power
Retail Base Rate Cases
In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
On February 7, 2018, Mississippi Power revised its annual projected Performance Evaluation Plan (PEP) filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a
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performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.
On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
Kemper County Energy Facility
Overview
The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper County energy facility. The mine, operated by North American Coal Corporation, started
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commercial operation in 2013. In connection with the Kemper County energy facility construction, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also
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reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.
In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets.
Lignite Mine and CO2 Pipeline Facilities
Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO2. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to
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revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
Nuclear Construction
Project Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds.
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Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
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Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.
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Southern Company and Subsidiary Companies 2017 Annual Report
In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
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| | |
Note | | Page |
1 | Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017. As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs. The ultimate outcome of these matters cannot be determined at this time. Other Matters As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. The ultimate outcome of these matters cannot be determined at this time. Other Matters A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural | |
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5 | | |
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NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc.
At December 31, 2017, Alabama Power's, Georgia Power's, Southern Power's, and Southern Company Gas' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
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| | | | | | | | | | | | | | |
Facility (Type) | Percent Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP |
| | | (in millions) |
Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | % | | $ | 3,564 |
| | $ | 2,141 |
| | $ | 70 |
|
Plant Hatch (nuclear) | 50.1 |
| | 1,321 |
| | 595 |
| | 87 |
|
Plant Miller (coal) Units 1 and 2 | 91.8 |
| | 1,717 |
| | 619 |
| | 54 |
|
Plant Scherer (coal) Units 1 and 2 | 8.4 |
| | 261 |
| | 93 |
| | 8 |
|
Plant Wansley (coal) | 53.5 |
| | 1,053 |
| | 335 |
| | 72 |
|
Rocky Mountain (pumped storage) | 25.4 |
| | 182 |
| | 132 |
| | — |
|
Plant Stanton (combined cycle) Unit A | 65.0 |
| | 155 |
| | 55 |
| | — |
|
Dalton Pipeline (natural gas pipeline) | 50.0 |
| | 241 |
| | 2 |
| | 13 |
|
Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under "Nuclear Construction" for additional information.
Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.
Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
NOTES (continued)
Alabama PowerSouthern Company 2015and Subsidiary Companies 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General5. INCOME TAXES
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
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| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current | $ | (62 | ) | | $ | 1,184 |
| | $ | (177 | ) |
Deferred | (6 | ) | | (342 | ) | | 1,266 |
|
| (68 | ) | | 842 |
| | 1,089 |
|
State — | | | | | |
Current | 37 |
| | (108 | ) | | (33 | ) |
Deferred | 173 |
| | 217 |
| | 138 |
|
| 210 |
| | 109 |
| | 105 |
|
Total | $ | 142 |
| | $ | 951 |
| | $ | 1,194 |
|
Net cash payments (refunds) for income taxes in 2017, 2016, and 2015 were $(410) million, $(148) million, and $(9) million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Deferred tax liabilities — | | | |
Accelerated depreciation | $ | 10,267 |
| | $ | 15,392 |
|
Property basis differences | 955 |
| | 2,708 |
|
Leveraged lease basis differences | 251 |
| | 314 |
|
Employee benefit obligations | 516 |
| | 737 |
|
Premium on reacquired debt | 54 |
| | 89 |
|
Regulatory assets associated with employee benefit obligations | 1,046 |
| | 1,584 |
|
Regulatory assets associated with AROs | 1,225 |
| | 1,781 |
|
Other | 697 |
| | 907 |
|
Total | 15,011 |
| | 23,512 |
|
Deferred tax assets — | | | |
Federal effect of state deferred taxes | 326 |
| | 597 |
|
Employee benefit obligations | 1,307 |
| | 1,868 |
|
Over recovered fuel clause | — |
| | 66 |
|
Other property basis differences | 446 |
| | 401 |
|
Deferred costs | 69 |
| | 100 |
|
ITC carryforward | 2,420 |
| | 1,974 |
|
Federal NOL carryforward | 518 |
| | 1,084 |
|
Unbilled revenue | 57 |
| | 92 |
|
Other comprehensive losses | 84 |
| | 152 |
|
AROs | 1,197 |
| | 1,732 |
|
Estimated Loss on Kemper IGCC | 722 |
| | 484 |
|
Deferred state tax assets | 328 |
| | 266 |
|
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 465 |
| | — |
|
Other | 485 |
| | 679 |
|
Total | 8,424 |
| | 9,495 |
|
Valuation allowance | (149 | ) | | (23 | ) |
Total deferred income taxes | 6,736 |
| | 14,040 |
|
Portion included in accumulated deferred tax assets | (106 | ) | | (52 | ) |
Accumulated deferred income taxes | $ | 6,842 |
| | $ | 14,092 |
|
The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities.
At December 31, 2017, the tax-related regulatory assets to be recovered from customers were $825 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.
At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $7.3 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and the natural gas distribution utilities are amortized over the life of the related property with such amortization normally applied as a credit to
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2017, $22 million in 2016, and $21 million in 2015. Southern Power's deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. No cash was received related to these incentives in 2017 and 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. See "Unrecognized Tax Benefits" below for further information.
Tax Credit Carryforwards
At December 31, 2017, Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $2.1 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling approximately $318 million, which will expire between 2020 and 2027 but are expected to be fully utilized.
Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will begin expiring in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.
At December 31, 2017, the state NOL carryforwards for Southern Company's subsidiaries were as follows:
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| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Begins Expiring |
| (in millions) | |
Mississippi | $ | 2,890 |
| $ | 114 |
| 2032 |
Oklahoma | 986 |
| 47 |
| 2036 |
Georgia | 524 |
| 23 |
| 2019 |
New York | 229 |
| 13 |
| 2036 |
New York City | 209 |
| 15 |
| 2036 |
Florida | 304 |
| 13 |
| 2034 |
Other states | 465 |
| 24 |
| Various |
Total | $ | 5,607 |
| $ | 249 |
|
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
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| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | 12.5 |
| | 2.1 |
| | 1.9 |
|
Employee stock plans dividend deduction | (4.1 | ) | | (1.2 | ) | | (1.2 | ) |
Non-deductible book depreciation | 3.1 |
| | 0.9 |
| | 1.2 |
|
AFUDC-Equity | (2.6 | ) | | (2.0 | ) | | (2.2 | ) |
Non-deductible equity portion on Kemper IGCC write-off | 15.7 |
| | — |
| | — |
|
ITC basis difference | (1.7 | ) | | (5.0 | ) | | (1.5 | ) |
Federal PTCs | (12.1 | ) | | (1.2 | ) | | — |
|
Amortization of ITC | (4.2 | ) | | (0.9 | ) | | (0.5 | ) |
Tax Reform Legislation | (25.6 | ) | | — |
| | — |
|
Other | (2.7 | ) | | (0.4 | ) | | 0.2 |
|
Effective income tax rate | 13.3 | % | | 27.3 | % | | 32.9 | % |
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs. However, in 2017, the effective tax rate was primarily lower due to the remeasurement of deferred income taxes resulting from the Tax Reform Legislation.
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
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| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Unrecognized tax benefits at beginning of year | $ | 484 |
| | $ | 433 |
| | $ | 170 |
|
Tax positions increase from current periods | 10 |
| | 45 |
| | 43 |
|
Tax positions increase from prior periods | 10 |
| | 21 |
| | 240 |
|
Tax positions decrease from prior periods | (196 | ) | | (15 | ) | | (20 | ) |
Reductions due to settlements | (290 | ) | | — |
| | — |
|
Balance at end of year | $ | 18 |
| | $ | 484 |
| | $ | 433 |
|
The tax positions increase from current and prior periods for 2017 and 2016 relate primarily to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as deductions for R&E expenditures associated with the Kemper County energy facility. The tax positions decrease from prior periods for 2017 and 2016, and the reductions due to settlements for 2017, relate primarily to the
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
settlement of R&E expenditures associated with the Kemper County energy facility and federal income tax benefits from deferred ITCs. See Note 3 under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction" herein for more information.
The impact on Southern Company's effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| 2017 |
| 2016 |
| 2015 |
| (in millions) |
Tax positions impacting the effective tax rate | $ | 18 |
|
| $ | 20 |
|
| $ | 10 |
|
Tax positions not impacting the effective tax rate | — |
|
| 464 |
|
| 423 |
|
Balance of unrecognized tax benefits | $ | 18 |
|
| $ | 484 |
|
| $ | 433 |
|
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility and Southern Company's estimate of the uncertainty related to the amount of those benefits. The tax positions not impacting the effective tax rate for 2016 and 2015 relate to deductions for R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented.
Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. As a result of this approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.
6. FINANCING
Securities Due Within One Year
A summary of scheduled maturities of securities due within one year at December 31 was as follows:
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| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Senior notes | $ | 2,354 |
| | $ | 1,995 |
|
Other long-term debt | 1,420 |
| | 485 |
|
Revenue bonds(*) | 90 |
| | 76 |
|
Capitalized leases | 31 |
| | 32 |
|
Unamortized debt issuance expense/discount | (3 | ) | | (1 | ) |
Total | $ | 3,892 |
| | $ | 2,587 |
|
| |
(*) | Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Maturities through 2022 applicable to total long-term debt are as follows: $3.9 billion in 2018; $3.2 billion in 2019; $3.2 billion in 2020; $3.1 billion in 2021; and $2.2 billion in 2022.
Bank Term Loans
Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
At December 31, 2017, Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company (the Company)had outstanding bank term loans totaling $450 million, $45 million, $250 million, $900 million, and $420 million, respectively, of which $1.5 billion are reflected in the statements of capitalization as long-term debt and $600 million are reflected in the balance sheet as notes payable. At December 31, 2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable.
In June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018.
The outstanding bank loans as of December 31, 2017 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017, each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into the Loan Guarantee Agreement in 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for Eligible Project Costs. Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.
All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
Upon satisfaction of all conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
At both December 31, 2017 and 2016, Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
Senior Notes
Southern Company and its subsidiaries issued a total of $4.0 billion of senior notes in 2017. Southern Company issued $0.3 billion and its subsidiaries issued a total of $3.7 billion. The proceeds of Southern Company's issuances were used to repay short-term indebtedness and for other general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs. A portion of the proceeds of Gulf Power's senior note issuances was used to redeem all of Gulf Power's outstanding shares of preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.
At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $35.1 billion and $33.0 billion, respectively, of senior notes outstanding. At December 31, 2017 and 2016, Southern Company had a total of $10.2 billion and $10.3 billion, respectively, of senior notes outstanding. These amounts include senior notes due within one year.
Since Southern Company is a wholly ownedholding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.
Junior Subordinated Notes
At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion, respectively, of junior subordinated notes outstanding.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of Georgia Power's preferred and preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2017 and 2016, which includes pollution control revenue bonds classified as due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
Plant Daniel Revenue Bonds
In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information.
Gas Facility Revenue Bonds
Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the parentNew Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
agencies or counties to investors, and proceeds from each issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million.
The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.
Other Revenue Bonds
Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper County energy facility and related facilities.
Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2017 and 2016. Such amounts are reflected in the statements of capitalization as other long-term debt.
First Mortgage Bonds
Nicor Gas, a subsidiary of Southern Company Gas, had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016, respectively. These bonds have been issued with maturities ranging from 2019 to 2057. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See "Assets Subject to Lien" herein for additional information.
On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.
Long-Term Debt Payable to an Affiliated Trust
Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million outstanding as of December 31, 2017 and 2016, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2017 and 2016, trust preferred securities of $200 million were outstanding.
Capital Leases
Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt.
In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which resulted in a capital lease obligation of $74 million at December 31, 2016. Following the suspension of the Kemper IGCC, Mississippi Power entered into an asset purchase and settlement agreement in December 2017 with the lessor, which terminated the capital lease obligation. See Note 3 under "Kemper County Energy Facility" for additional information.
At December 31, 2017 and 2016, the capitalized lease obligations for Georgia Power's corporate headquarters building were $22 million and $28 million, respectively, with an annual interest rate of 7.9%.
At December 31, 2017 and 2016, a subsidiary of Southern Company had capital lease obligations of approximately $177 million and $29 million, respectively, for an office building and certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.5% to 4.7%.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of fourSouthern Company or any of its other subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2017.
The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant Daniel Revenue Bonds" herein for additional information.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.
The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See "First Mortgage Bonds" herein for additional information.
Under the terms of the PPA and the expansion PPA for Southern Power's Mankato project, which was acquired in 2016, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. See Note 12 under "Southern Power" for additional information.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock solar facility in Pecos County, Texas. Roserock is in a litigation dispute with McCarthy Building Companies, Inc. (McCarthy) regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. Southern Power intends to vigorously pursue its claims against McCarthy and defend against McCarthy's claims, the ultimate outcome of which cannot be determined at this time.
Bank Credit Arrangements
At December 31, 2017, committed credit arrangements with banks were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2018 | | 2019 | | 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
Southern Company(a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Southern Company Consolidated | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional electric operating companies, Southern Power SCS, SouthernLINC Wireless,Company, Southern Company Holdings, Inc. (Southern Holdings)Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of the other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants.
A portion of the $8.1 billion unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of short-term borrowings were as follows:
|
| | | | | | |
| Short-term Debt at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2017: | | | |
Commercial paper | $ | 1,832 |
| | 1.8 | % |
Short-term bank debt | 607 |
| | 2.3 | % |
Total | $ | 2,439 |
| | 1.9 | % |
December 31, 2016: | | | |
Commercial paper | $ | 1,909 |
| | 1.1 | % |
Short-term bank debt | 123 |
| | 1.7 | % |
Total | $ | 2,032 |
| | 1.1 | % |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017 and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016.
Redeemable Preferred Stock of Subsidiaries
At December 31, 2016, each of the traditional electric operating companies had outstanding preferred and/or preference stock. During 2017, Alabama Power and Gulf Power each redeemed all of its outstanding preference stock and Georgia Power redeemed all of its outstanding preferred and preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power did not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity.
The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:
|
| | | |
| Redeemable Preferred Stock of Subsidiaries |
| (in millions) |
Balance at December 31, 2014 | $ | 375 |
|
Issued | — |
|
Redeemed | (262 | ) |
Issuance costs | 5 |
|
Balance at December 31, 2015: | 118 |
|
Issued | — |
|
Redeemed | — |
|
Balance at December 31, 2016: | 118 |
|
Issued | 250 |
|
Redeemed | (38 | ) |
Issuance costs | (6 | ) |
Balance at December 31, 2017: | $ | 324 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2017, 2016, and 2015, the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion, $4.4 billion, and $4.8 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system's future fuel needs will continue to be purchased under long-term commitments.
In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $235 million, $232 million, and $227 million for 2017, 2016, and 2015, respectively.
Estimated total obligations under these commitments at December 31, 2017 were as follows:
|
| | | | | | | |
| Operating Leases | | Other |
| (in millions) |
2018 | $ | 247 |
| | $ | 7 |
|
2019 | 250 |
| | 6 |
|
2020 | 247 |
| | 4 |
|
2021 | 249 |
| | 5 |
|
2022 | 252 |
| | 4 |
|
2023 and thereafter | 806 |
| | 38 |
|
Total | $ | 2,051 |
| | $ | 64 |
|
Pipeline Charges, Storage Capacity, and Gas Supply
Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.
Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:
|
| | | |
| Pipeline Charges, Storage Capacity, and Gas Supply |
| (in millions) |
2018 | $ | 813 |
|
2019 | 552 |
|
2020 | 416 |
|
2021 | 375 |
|
2022 | 339 |
|
2023 and thereafter | 2,294 |
|
Total | $ | 4,789 |
|
Operating Leases
The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $176 million, $169 million, and $130 million for 2017, 2016, and 2015, respectively. Southern Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, estimated minimum lease payments under operating leases were as follows:
|
| | | | | | | | | | | |
| Minimum Lease Payments |
| Barges & Railcars | | Other(*) | | Total |
| (in millions) |
2018 | $ | 21 |
| | $ | 128 |
| | $ | 149 |
|
2019 | 11 |
| | 113 |
| | 124 |
|
2020 | 9 |
| | 99 |
| | 108 |
|
2021 | 8 |
| | 87 |
| | 95 |
|
2022 | 6 |
| | 77 |
| | 83 |
|
2023 and thereafter | 5 |
| | 963 |
| | 968 |
|
Total | $ | 60 |
| | $ | 1,467 |
| | $ | 1,527 |
|
| |
(*) | Includes operating leases for cellular tower space, facilities, vehicles, and other equipment. |
For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions.
In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $44 million. At the termination of the leases, the lessee may renew the lease, exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.
Guarantees
In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.
As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.
8. COMMON STOCK
Stock Issued
During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
Shares Reserved
At December 31, 2017, a total of 71 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below), and an at-the-market program. Of the total 71 million shares reserved, there were 13 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2017.
Stock-Based Compensation
Stock-based compensation primarily in the form of performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017, there were 5,112 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs.
In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan.
Performance Share Units
Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
In determining the fair value of the TSR-based awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
|
| | | | | |
Year Ended December 31 | 2017 | | 2016 | | 2015 |
Expected volatility | 15.6% | | 15.0% | | 12.9% |
Expected term (in years) | 3 | | 3 | | 3 |
Interest rate | 1.4% | | 0.8% | | 1.0% |
Weighted average grant-date fair value | $49.08 | | $45.06 | | $46.38 |
The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21, $48.87, and $47.75, respectively.
Total unvested performance share units outstanding as of December 31, 2016 were 3.2 million. During 2017, 1.2 million performance share units were granted and 1.5 million performance share units were vested or forfeited, resulting in 2.9 million
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
unvested performance share units outstanding at December 31, 2017. The number of shares to be issued for the three-year performance and vesting period ended December 31, 2017 will be determined in the first quarter 2018.
For the years ended December 31, 2017, 2016, and 2015, total compensation cost for performance share units recognized in income was $74 million, $96 million, and $88 million, respectively, with the related tax benefit also recognized in income of $29 million, $37 million, and $34 million, respectively. As of December 31, 2017, $30 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25.
During 2017, 0.6 million restricted stock units were granted and 0.1 million restricted stock units were vested or forfeited, resulting in 0.7 million unvested restricted stock units outstanding at December 31, 2017, including previously issued restricted stock units related to other employee retention agreements.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $25 million with the related tax benefit also recognized in income of $10 million. As of December 31, 2017, $8 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.
Stock Options
In 2015, Southern Company discontinued the granting of stock options and all outstanding options have vested. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
Southern Company's activity in the stock option program for 2017 is summarized below:
|
| | | | | | |
| Shares Subject to Option | | Weighted Average Exercise Price |
| (in millions) | | |
Outstanding at December 31, 2016 | 24.6 |
| | $ | 41.28 |
|
Exercised | 6.0 |
| | 40.03 |
|
Cancelled | — |
| | 39.90 |
|
Outstanding and Exercisable at December 31, 2017 | 18.6 |
| | $ | 41.68 |
|
As of December 31, 2017, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately five years and the aggregate intrinsic value for the options outstanding and options exercisable was $119 million.
Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $64 million, $120 million, and $48 million, respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $25 million, $46 million, and $19 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2017, 2016, and 2015 was $239 million, $448 million, and $154 million, respectively.
Southern Company Gas Restricted Stock Awards
At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 0.7 million restricted stock units with a grant-date fair value of $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration.
For the years ended December 31, 2017 and 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million, respectively, and the related tax benefit also recognized in income was $4 million for each year. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months.
Southern Company Gas Change in Control Awards
Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares).
The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance.
For the years ended December 31, 2017 and 2016, total compensation cost for the change in control awards recognized in income was $12 million and $4 million, respectively. The related tax benefit also recognized in income was $6 million for the year ended December 31, 2017 and an immaterial amount for the year ended December 31, 2016. As of December 31, 2017, approximately $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months.
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows:
|
| | | | | | | | |
| Average Common Stock Shares |
| 2017 | | 2016 | | 2015 |
| (in millions) |
As reported shares | 1,000 |
| | 951 |
| | 910 |
|
Effect of options and performance share award units | 8 |
| | 7 |
| | 4 |
|
Diluted shares | 1,008 |
| | 958 |
| | 914 |
|
Prior to the adoption of ASU 2016-09 in 2016, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. Stock options and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented.
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2017, consolidated retained earnings included $5.3 billion of undistributed retained earnings of the subsidiaries.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2017 under the NEIL policies would be $55 million and $81 million, respectively.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other directexpenses incurred. Uninsured losses and indirect subsidiaries.other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 331 |
| | $ | 239 |
| | $ | — |
| | $ | — |
| | $ | 570 |
|
Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Foreign currency derivatives | — |
| | 129 |
| | — |
| | — |
| | 129 |
|
Nuclear decommissioning trusts:(c) | | | | | | | | | |
Domestic equity | 690 |
| | 82 |
| | — |
| | — |
| | 772 |
|
Foreign equity | 62 |
| | 224 |
| | — |
| | — |
| | 286 |
|
U.S. Treasury and government agency securities | — |
| | 251 |
| | — |
| | — |
| | 251 |
|
Municipal bonds | — |
| | 68 |
| | — |
| | — |
| | 68 |
|
Corporate bonds | 21 |
| | 315 |
| | — |
| | — |
| | 336 |
|
Mortgage and asset backed securities | — |
| | 57 |
| | — |
| | — |
| | 57 |
|
Private equity | — |
| | — |
| | — |
| | 29 |
| | 29 |
|
Other | 19 |
| | 12 |
| | — |
| | — |
| | 31 |
|
Cash equivalents | 1,455 |
| | — |
| | — |
| | — |
| | 1,455 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 2,587 |
| | $ | 1,378 |
| | $ | 1 |
| | $ | 29 |
| | $ | 3,995 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 480 |
| | $ | 253 |
| | $ | — |
| | $ | — |
| | $ | 733 |
|
Interest rate derivatives | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Contingent consideration | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
Total | $ | 480 |
| | $ | 314 |
| | $ | 22 |
| | $ | — |
| | $ | 816 |
|
| |
(a) | Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $193 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 338 |
| | $ | 333 |
| | $ | — |
| | $ | — |
| | $ | 671 |
|
Interest rate derivatives | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Nuclear decommissioning trusts:(c) | | | | | | | | | |
Domestic equity | 589 |
| | 73 |
| | — |
| | — |
| | 662 |
|
Foreign equity | 48 |
| | 168 |
| | — |
| | — |
| | 216 |
|
U.S. Treasury and government agency securities | — |
| | 92 |
| | — |
| | — |
| | 92 |
|
Municipal bonds | — |
| | 73 |
| | — |
| | — |
| | 73 |
|
Corporate bonds | 22 |
| | 310 |
| | — |
| | — |
| | 332 |
|
Mortgage and asset backed securities | — |
| | 183 |
| | — |
| | — |
| | 183 |
|
Private equity | — |
| | — |
| | — |
| | 20 |
| | 20 |
|
Other | 11 |
| | 15 |
| | — |
| | — |
| | 26 |
|
Cash equivalents | 1,172 |
| | — |
| | — |
| | — |
| | 1,172 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 2,189 |
| | $ | 1,261 |
| | $ | 1 |
| | $ | 20 |
| | $ | 3,471 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 345 |
| | $ | 285 |
| | $ | — |
| | $ | — |
| | $ | 630 |
|
Interest rate derivatives | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Foreign currency derivatives | — |
| | 58 |
| | — |
| | — |
| | 58 |
|
Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
Total | $ | 345 |
| | $ | 372 |
| | $ | 18 |
| | $ | — |
| | $ | 735 |
|
| |
(a) | Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $62 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of December 31, 2017 and 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) |
|
|
|
|
As of December 31, 2017 | $ | 29 |
|
| $ | 21 |
|
| Not Applicable |
| Not Applicable |
As of December 31, 2016 | $ | 20 |
| | $ | 25 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.
As of December 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 48,151 |
| | $ | 51,348 |
|
2016 | $ | 45,080 |
| | $ | 46,286 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
11. DERIVATIVES
The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information.
Energy-Related Derivatives
Southern Company and certain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, adversely affect results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 621 million mmBtu for the Southern Company system, with the longest hedge date of 2021 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2026 for derivatives not designated as hedges.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 32 million mmBtu.
The estimated pre-tax gains (losses) related to energy-related derivatives that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 total $(11) million for Southern Company.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At December 31, 2017, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount |
| Interest Rate Received |
| Weighted Average Interest Rate Paid |
| Hedge Maturity Date |
| Fair Value Gain (Loss) December 31, 2017 |
| (in millions) |
|
|
|
|
|
|
| (in millions) |
Cash Flow Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| $ | 900 |
|
| 1-month LIBOR |
| 0.79% |
| March 2018 |
| $ | 1 |
|
Fair Value Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| 250 |
| | 5.40% | | 3-month LIBOR + 4.02% | | June 2018 | | — |
|
| 500 |
| | 1.95% | | 3-month LIBOR + 0.76% | | December 2018 | | (3 | ) |
| 200 |
| | 4.25% | | 3-month LIBOR + 2.46% | | December 2019 | | (1 | ) |
| 300 |
| | 2.75% | | 3-month LIBOR + 0.92% | | June 2020 | | (2 | ) |
| 1,500 |
| | 2.35% | | 1-month LIBOR + 0.87% | | July 2021 | | (31 | ) |
Total | $ | 3,650 |
|
|
|
|
|
|
|
| $ | (36 | ) |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2018 total $(20) million. Deferred gains and losses are expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017, the following foreign currency derivatives were outstanding: |
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
| $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 55 |
|
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 51 |
|
Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 106 |
|
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2018 total $(23) million.
Derivative Financial Statement Presentation and Amounts
Southern Company and its subsidiaries enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | |
| 2017 | | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 10 |
| $ | 43 |
| | $ | 73 |
| $ | 27 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 7 |
| 24 |
| | 25 |
| 33 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 17 |
| $ | 67 |
| | $ | 98 |
| $ | 60 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 14 |
| | $ | 23 |
| $ | 7 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | 1 |
| 4 |
| | 12 |
| 1 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 34 |
| | 1 |
| 28 |
|
Foreign currency derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| 23 |
| | — |
| 25 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 129 |
| — |
| | — |
| 33 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 133 |
| $ | 75 |
| | $ | 36 |
| $ | 94 |
|
Derivatives not designated as hedging instruments | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 380 |
| $ | 437 |
| | $ | 489 |
| $ | 483 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 170 |
| 215 |
| | 66 |
| 81 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| — |
| | 1 |
| — |
|
Total derivatives not designated as hedging instruments | $ | 550 |
| $ | 652 |
| | $ | 556 |
| $ | 564 |
|
Gross amounts recognized | $ | 700 |
| $ | 794 |
| | $ | 690 |
| $ | 718 |
|
Gross amounts offset(a) | $ | (405 | ) | $ | (598 | ) | | $ | (462 | ) | $ | (524 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 295 |
| $ | 196 |
| | $ | 228 |
| $ | 194 |
|
| |
(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively. |
| |
(b) | Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | | | | |
| Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (34 | ) | | $ | (16 | ) | | Other regulatory liabilities, current | $ | 7 |
| | $ | 56 |
|
| Other regulatory assets, deferred | (18 | ) | | (19 | ) | | Other regulatory liabilities, deferred | 1 |
| | 12 |
|
Total energy-related derivative gains (losses)(*) | | $ | (52 | ) | | $ | (35 | ) | | | $ | 8 |
| | $ | 68 |
|
| |
(*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |
| Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Amount |
| | Amount |
Derivative Category | 2017 |
| 2016 |
| 2015 |
| Statements of Income Location | 2017 |
| 2016 |
| 2015 |
| (in millions) |
| | (in millions) |
Energy-related derivatives | $ | (47 | ) |
| $ | 18 |
|
| $ | — |
|
| Depreciation and amortization | $ | (16 | ) |
| $ | 2 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
| Cost of natural gas | (2 | ) |
| (1 | ) |
| — |
|
Interest rate derivatives | (2 | ) |
| (180 | ) |
| (22 | ) |
| Interest expense, net of amounts capitalized | (21 | ) |
| (18 | ) |
| (9 | ) |
Foreign currency derivatives | 140 |
|
| (58 | ) |
| — |
|
| Interest expense, net of amounts capitalized | (23 | ) |
| (13 | ) |
| — |
|
|
|
|
|
|
|
|
|
|
| Other income (expense), net(*) | 160 |
|
| (82 | ) |
| — |
|
Total | $ | 91 |
|
| $ | (220 | ) |
| $ | (22 | ) |
|
| $ | 98 |
|
| $ | (112 | ) |
| $ | (9 | ) |
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record euro-denominated notes. |
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | | | | | |
Derivatives in Fair Value Hedging Relationships |
| Gain (Loss) |
Derivative Category | Statements of Income Location | 2017 | | 2016 | | 2015 |
| | (in millions) |
Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (22 | ) | | $ | (21 | ) | | $ | 2 |
|
For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: |
| | | | | | | | | | | | |
Derivatives Not Designated as Hedging Instruments |
| Unrealized Gain (Loss) Recognized in Income |
|
| Amount |
Derivative Category | Statements of Income Location | 2017 |
| 2016 |
| 2015 |
|
| (in millions) |
Energy-related derivatives | Wholesale electric revenues | $ | (4 | ) |
| $ | 2 |
|
| $ | (5 | ) |
| Fuel | — |
|
| — |
|
| 3 |
|
| Natural gas revenues(*) | (80 | ) |
| 33 |
|
| — |
|
| Cost of natural gas | (2 | ) |
| 3 |
|
| — |
|
Total |
| $ | (86 | ) |
| $ | 38 |
|
| $ | (2 | ) |
| |
(*) | Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.
At December 31, 2017, the fair value of energy-related and interest rate derivative liabilities with contingent features was $15 million and $7 million, respectively. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $14 million and $7 million for energy-related and interest rate derivative contracts, respectively.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Southern Company system maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2017, cash collateral held on deposit in broker margin accounts was $193 million.
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's exposure to counterparty credit risk. Southern Company may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
12. ACQUISITIONS AND DISPOSITIONS
Southern Company
Merger with Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
Southern Company Gas Purchase Price | |
| (in millions) |
Current assets | $ | 1,557 |
|
Property, plant, and equipment | 10,108 |
|
Goodwill | 5,967 |
|
Intangible assets | 400 |
|
Regulatory assets | 1,118 |
|
Other assets | 229 |
|
Current liabilities | (2,201 | ) |
Other liabilities | (4,742 | ) |
Long-term debt | (4,261 | ) |
Noncontrolling interest | (174 | ) |
Total purchase price | $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $3.9 billion and $1.7 billion and net income of $243 million and $114 million for 2017 and 2016, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.
|
| | | | | | |
| 2016 | 2015 |
| | |
Operating revenues (in millions) | $ | 21,791 |
| $ | 21,430 |
|
Net income attributable to Southern Company (in millions) | $ | 2,591 |
| $ | 2,665 |
|
Basic EPS | $ | 2.70 |
| $ | 2.85 |
|
Diluted EPS | $ | 2.68 |
| $ | 2.84 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
Acquisition of PowerSecure
In May 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
PowerSecure Purchase Price | |
| (in millions) |
Current assets | $ | 172 |
|
Property, plant, and equipment | 46 |
|
Intangible assets | 106 |
|
Goodwill | 284 |
|
Other assets | 4 |
|
Current liabilities | (121 | ) |
Long-term debt, including current portion | (48 | ) |
Deferred credits and other liabilities | (14 | ) |
Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
Southern Power
During 2017 and 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, Southern Power and the class B member are
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.
The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017.
|
| | | | | | | | | |
Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual/Expected COD | PPA Contract Period |
Business Acquisitions During the Year Ended December 31, 2017 |
Bethel | Wind | Invenergy Wind Global LLC, January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
Cactus Flats(a) | Wind | RES America Developments, Inc. July 31, 2017 | 148 | Concho County, TX | 100 | % | | Third quarter 2018 | 12 years and 15 years |
Business Acquisitions Subsequent to December 31, 2017 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC, January 26, 2018 | 20 | Kern County, CA | 100% of Class B |
| (b) | March 2018 | 20 years |
| |
(a) | On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. |
| |
(b) | Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement. |
Business Acquisitions During the Year Ended December 31, 2017
Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million. The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows:
|
| | | |
| 2017 |
| (in millions) |
Restricted cash | $ | 16 |
|
CWIP | 534 |
|
Other assets | 5 |
|
Accounts payable | (16 | ) |
Total purchase price | $ | 539 |
|
In 2017, total revenues of $15 million and net income of $17 million, primarily as a result of PTCs, was recognized by Southern Power related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Construction Projects in Progress
During the year ended December 31, 2017, in accordance with its overall growth strategy, Southern Power continued construction on the 345-MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, construction costs included in CWIP related to these projects totaled $188 million. The ultimate outcome of these matters cannot be determined at this time.
Development Projects
During 2017, as part of Southern Power's renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
The following table presents Southern Power's acquisitions for the year ended December 31, 2016.
|
| | | | | | | | | | |
Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual COD | PPA Contract Period |
Acquisitions for the Year Ended December 31, 2016 |
Boulder 1 | Solar | SunPower November 16, 2016 | 100 | | Clark County, NV | 51 | % | (a) | December 2016 | 20 years |
Calipatria | Solar | Solar Frontier Americas Holding LLC February 11, 2016 | 20 | | Imperial County, CA | 100 | % | (b) | February 2016 | 20 years |
East Pecos | Solar | First Solar, Inc. March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | March 2017 | 15 years |
Grant Plains | Wind | Apex Clean Energy Holdings, LLC August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | 20 years and 12 years (c) |
Grant Wind | Wind | Apex Clean Energy Holdings, LLC April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | 20 years |
Henrietta | Solar | SunPower July 1, 2016 | 102 | | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
Lamesa | Solar | RES America Developments Inc. July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | April 2017 | 15 years |
Mankato (d) | Natural Gas | Calpine Corporation October 26, 2016 | 375 | | Mankato, MN | 100 | % | | N/A (e) | 10 years |
Passadumkeag | Wind | Quantum Utility Generation, LLC June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
Rutherford | Solar | Cypress Creek Renewables, LLC July 1, 2016 | 74 | | Rutherford County, NC | 100 | % | (b) | December 2016 | 15 years |
Salt Fork | Wind | EDF Renewable Energy, Inc. December 1, 2016 | 174 | | Donley and Gray Counties, TX | 100 | % | | December 2016 | 14 years and 12 years |
Tyler Bluff | Wind | EDF Renewable Energy, Inc. December 21, 2016 | 125 | | Cooke County, TX | 100 | % | | December 2016 | 12 years |
Wake Wind | Wind | Invenergy October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | (f) | October 2016 | 12 years |
| |
(a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
(b) | Southern Power originally purchased 90%, with a minority owner owning 10%. During 2017, Southern Power acquired the remaining 10% ownership interest. |
| |
(c) | In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
(d) | Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. |
| |
(e) | The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility. |
| |
(f) | Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Acquisitions During the Year Ended December 31, 2016
Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to Southern Power was approximately $2.6 billion for these acquisitions. In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows:
|
| | | |
| 2016 |
| (in millions) |
CWIP | $ | 2,354 |
|
Property, plant, and equipment | 302 |
|
Intangible assets (a) | 128 |
|
Other assets | 52 |
|
Accounts payable | (16 | ) |
Debt | (217 | ) |
Total purchase price | $ | 2,603 |
|
| |
Funded by: | |
Southern Power (b) (c) | $ | 2,345 |
|
Noncontrolling interests (d) (e) | 258 |
|
Total purchase price | $ | 2,603 |
|
| |
(a) | Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. |
| |
(b) | At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. |
| |
(c) | Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. |
| |
(d) | Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. |
| |
(e) | Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. |
Southern Company Gas
Investment in Southern Natural Gas
In September 2016, Southern Company Gas completed its acquisition from Kinder Morgan, Inc. of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of the acquisition was approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
Acquisition of Remaining Interest in SouthStar
SouthStar Energy Services, LLC (SouthStar) is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont Natural Gas Company, Inc.'s (Piedmont) owning the remaining 15%. In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million.
Proposed Sale of Elizabethtown Gas and Elkton Gas
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
13. SEGMENT AND RELATED INFORMATION
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – the Company,Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $392 million, $419 million, and $417 million in 2017, 2016, and 2015, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were $23 million and $119 million, respectively, in 2017 and $11 million and $17 million, respectively, in 2016. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2017, 2016, and 2015 was as follows:
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| (in millions) |
2017 | | | | | | | | |
Operating revenues | $ | 16,884 |
| $ | 2,075 |
| $ | (419 | ) | $ | 18,540 |
| $ | 3,920 |
| $ | 741 |
| $ | (170 | ) | $ | 23,031 |
|
Depreciation and amortization | 1,954 |
| 503 |
| — |
| 2,457 |
| 501 |
| 52 |
| — |
| 3,010 |
|
Interest income | 14 |
| 7 |
| — |
| 21 |
| 3 |
| 11 |
| (9 | ) | 26 |
|
Earnings from equity method investments | 1 |
| — |
| — |
| 1 |
| 106 |
| (1 | ) | — |
| 106 |
|
Interest expense | 820 |
| 191 |
| — |
| 1,011 |
| 200 |
| 490 |
| (7 | ) | 1,694 |
|
Income taxes | 1,021 |
| (939 | ) | — |
| 82 |
| 367 |
| (307 | ) | — |
| 142 |
|
Segment net income (loss)(a)(b)(c) | (193 | ) | 1,071 |
| — |
| 878 |
| 243 |
| (279 | ) | — |
| 842 |
|
Total assets | 72,204 |
| 15,206 |
| (325 | ) | 87,085 |
| 22,987 |
| 2,552 |
| (1,619 | ) | 111,005 |
|
Gross property additions | 3,836 |
| 268 |
| — |
| 4,104 |
| 1,525 |
| 355 |
| — |
| 5,984 |
|
2016 | | | | | | | | |
Operating revenues | $ | 16,803 |
| $ | 1,577 |
| $ | (439 | ) | $ | 17,941 |
| $ | 1,652 |
| $ | 463 |
| $ | (160 | ) | $ | 19,896 |
|
Depreciation and amortization | 1,881 |
| 352 |
| — |
| 2,233 |
| 238 |
| 31 |
| — |
| 2,502 |
|
Interest income | 6 |
| 7 |
| — |
| 13 |
| 2 |
| 20 |
| (15 | ) | 20 |
|
Earnings from equity method investments | 2 |
| — |
| — |
| 2 |
| 60 |
| (3 | ) | — |
| 59 |
|
Interest expense | 814 |
| 117 |
| — |
| 931 |
| 81 |
| 317 |
| (12 | ) | 1,317 |
|
Income taxes | 1,286 |
| (195 | ) | — |
| 1,091 |
| 76 |
| (216 | ) | — |
| 951 |
|
Segment net income (loss)(a) (b) | 2,233 |
| 338 |
| — |
| 2,571 |
| 114 |
| (230 | ) | (7 | ) | 2,448 |
|
Total assets | 72,141 |
| 15,169 |
| (316 | ) | 86,994 |
| 21,853 |
| 2,474 |
| (1,624 | ) | 109,697 |
|
Gross property additions | 4,852 |
| 2,114 |
| — |
| 6,966 |
| 618 |
| 41 |
| (1 | ) | 7,624 |
|
2015 | | | | | | | | |
Operating revenues | $ | 16,491 |
| $ | 1,390 |
| $ | (439 | ) | $ | 17,442 |
| $ | — |
| $ | 152 |
| $ | (105 | ) | $ | 17,489 |
|
Depreciation and amortization | 1,772 |
| 248 |
| — |
| 2,020 |
| — |
| 14 |
| — |
| 2,034 |
|
Interest income | 19 |
| 2 |
| 1 |
| 22 |
| — |
| 6 |
| (5 | ) | 23 |
|
Earnings from equity method investments | 1 |
| — |
| — |
| 1 |
| — |
| (1 | ) | — |
| — |
|
Interest expense | 697 |
| 77 |
| — |
| 774 |
| — |
| 69 |
| (3 | ) | 840 |
|
Income taxes | 1,305 |
| 21 |
| — |
| 1,326 |
| — |
| (132 | ) | — |
| 1,194 |
|
Segment net income (loss)(a) (b) | 2,186 |
| 215 |
| — |
| 2,401 |
| — |
| (32 | ) | (2 | ) | 2,367 |
|
Total assets | 69,052 |
| 8,905 |
| (397 | ) | 77,560 |
| — |
| 1,819 |
| (1,061 | ) | 78,318 |
|
Gross property additions | 5,124 |
| 1,005 |
| — |
| 6,129 |
| — |
| 40 |
| — |
| 6,169 |
|
| |
(a) | Attributable to Southern Company. |
| |
(b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ($2.4 billion after tax) in 2017, $428 million ($264 million after tax) in 2016, and $365 million ($226 million after tax) in 2015. See Note 3 under "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information. |
| |
(c) | Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Products and Services
|
| | | | | | | | | | | | | | | |
Electric Utilities' Revenues |
Year | Retail | | Wholesale | | Other | | Total |
| (in millions) |
2017 | $ | 15,330 |
| | $ | 2,426 |
| | $ | 784 |
| | $ | 18,540 |
|
2016 | 15,234 |
| | 1,926 |
| | 781 |
| | 17,941 |
|
2015 | 14,987 |
| | 1,798 |
| | 657 |
| | 17,442 |
|
|
| | | | | | | | | | | | | | | |
Southern Company Gas' Revenues |
Year | Gas Distribution Operations | | Gas Marketing Services | | All Other | | Total |
| (in millions) |
2017 | $ | 3,024 |
| | $ | 860 |
| | $ | 36 |
| | $ | 3,920 |
|
2016 | 1,266 |
| | 354 |
| | 32 |
| | 1,652 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2017 and 2016 is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Consolidated Net Income Attributable to Southern Company | | Per Common Share |
| Operating Revenues | | Operating Income | | | Basic Earnings | | Diluted Earnings | | | | Trading Price Range |
Quarter Ended | | Dividends | | High | | Low |
| (in millions) | | | | | | | | | | |
March 2017 | $ | 5,771 |
| | $ | 1,306 |
| | $ | 658 |
| | $ | 0.66 |
| | $ | 0.66 |
| | $ | 0.5600 |
| | $ | 51.47 |
| | $ | 47.57 |
|
June 2017 | 5,430 |
| | (1,594 | ) | | (1,381 | ) | | (1.38 | ) | | (1.37 | ) | | 0.5800 |
| | 51.97 |
| | 47.87 |
|
September 2017 | 6,201 |
| | 2,045 |
| | 1,069 |
| | 1.07 |
| | 1.06 |
| | 0.5800 |
| | 50.80 |
| | 46.71 |
|
December 2017 | 5,629 |
| | 794 |
| | 496 |
| | 0.49 |
| | 0.49 |
| | 0.5800 |
| | 53.51 |
| | 47.92 |
|
| | | | | | | | | | | | | | | |
March 2016 | $ | 3,992 |
| | $ | 940 |
| | $ | 489 |
| | $ | 0.53 |
| | $ | 0.53 |
| | $ | 0.5425 |
| | $ | 51.73 |
| | $ | 46.00 |
|
June 2016 | 4,459 |
| | 1,185 |
| | 623 |
| | 0.67 |
| | 0.66 |
| | 0.5600 |
| | 53.64 |
| | 47.62 |
|
September 2016 | 6,264 |
| | 1,917 |
| | 1,139 |
| | 1.18 |
| | 1.17 |
| | 0.5600 |
| | 54.64 |
| | 50.00 |
|
December 2016 | 5,181 |
| | 587 |
| | 197 |
| | 0.20 |
| | 0.20 |
| | 0.5600 |
| | 52.23 |
| | 46.20 |
|
As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $208 million ($185 million after tax) in the fourth quarter 2017, $34 million ($21 million after tax) in the third quarter 2017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $108 million ($67 million after tax) in the first quarter 2017, $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, and $53 million ($33 million after tax) in the first quarter 2016. See Note 3 under "Kemper County Energy Facility" for additional information.
As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017. See Note 5 for additional information.
The Southern Company system's business is influenced by seasonal weather conditions.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Total Assets (in millions)(b)(c) | $ | 111,005 |
| | $ | 109,697 |
| | $ | 78,318 |
| | $ | 70,233 |
| | $ | 64,264 |
|
Gross Property Additions (in millions) | $ | 5,984 |
| | $ | 7,624 |
| | $ | 6,169 |
| | $ | 6,522 |
| | $ | 5,868 |
|
Return on Average Common Equity (percent)(d) | 3.44 |
| | 10.80 |
| | 11.68 |
| | 10.08 |
| | 8.82 |
|
Cash Dividends Paid Per Share of Common Stock | $ | 2.3000 |
| | $ | 2.2225 |
| | $ | 2.1525 |
| | $ | 2.0825 |
| | $ | 2.0125 |
|
Consolidated Net Income Attributable to Southern Company (in millions)(d) | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
|
Earnings Per Share — | | | | | | | | | |
Basic | $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
| | $ | 2.19 |
| | $ | 1.88 |
|
Diluted | 0.84 |
| | 2.55 |
| | 2.59 |
| | 2.18 |
| | 1.87 |
|
Capitalization (in millions): | | | | | | | | | |
Common stock equity | $ | 24,167 |
| | $ | 24,758 |
| | $ | 20,592 |
| | $ | 19,949 |
| | $ | 19,008 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 1,361 |
| | 1,854 |
| | 1,390 |
| | 977 |
| | 756 |
|
Redeemable preferred stock of subsidiaries | 324 |
| | 118 |
| | 118 |
| | 375 |
| | 375 |
|
Redeemable noncontrolling interests | — |
| | 164 |
| | 43 |
| | 39 |
| | — |
|
Long-term debt(b) | 44,462 |
| | 42,629 |
| | 24,688 |
| | 20,644 |
| | 21,205 |
|
Total (excluding amounts due within one year) | $ | 70,314 |
| | $ | 69,523 |
| | $ | 46,831 |
| | $ | 41,984 |
| | $ | 41,344 |
|
Capitalization Ratios (percent): | | | | | | | | | |
Common stock equity | 34.4 |
| | 35.6 |
| | 44.0 |
| | 47.5 |
| | 46.0 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 1.9 |
| | 2.7 |
| | 3.0 |
| | 2.3 |
| | 1.8 |
|
Redeemable preferred stock of subsidiaries | 0.5 |
| | 0.2 |
| | 0.3 |
| | 0.9 |
| | 0.9 |
|
Redeemable noncontrolling interests | — |
| | 0.2 |
| | 0.1 |
| | 0.1 |
| | — |
|
Long-term debt(b) | 63.2 |
| | 61.3 |
| | 52.6 |
| | 49.2 |
| | 51.3 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Other Common Stock Data: | | | | | | | | | |
Book value per share | $ | 23.99 |
| | $ | 25.00 |
| | $ | 22.59 |
| | $ | 21.98 |
| | $ | 21.43 |
|
Market price per share: | | | | | | | | | |
High | $ | 53.51 |
| | $ | 54.64 |
| | $ | 53.16 |
| | $ | 51.28 |
| | $ | 48.74 |
|
Low | 46.71 |
| | 46.00 |
| | 41.40 |
| | 40.27 |
| | 40.03 |
|
Close (year-end) | 48.09 |
| | 49.19 |
| | 46.79 |
| | 49.11 |
| | 41.11 |
|
Market-to-book ratio (year-end) (percent) | 200.5 |
| | 196.8 |
| | 207.2 |
| | 223.4 |
| | 191.8 |
|
Price-earnings ratio (year-end) (times) | 57.3 |
| | 19.1 |
| | 18.0 |
| | 22.4 |
| | 21.9 |
|
Dividends paid (in millions) | $ | 2,300 |
| | $ | 2,104 |
| | $ | 1,959 |
| | $ | 1,866 |
| | $ | 1,762 |
|
Dividend yield (year-end) (percent) | 4.8 |
| | 4.5 |
| | 4.6 |
| | 4.2 |
| | 4.9 |
|
Dividend payout ratio (percent) | 273.2 |
| | 86.0 |
| | 82.7 |
| | 95.0 |
| | 107.1 |
|
Shares outstanding (in thousands): | | | | | | | | | |
Average | 1,000,336 |
| | 951,332 |
| | 910,024 |
| | 897,194 |
| | 876,755 |
|
Year-end | 1,007,603 |
| | 990,394 |
| | 911,721 |
| | 907,777 |
| | 887,086 |
|
Stockholders of record (year-end) | 120,803 |
| | 126,338 |
| | 131,771 |
| | 137,369 |
| | 143,800 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million and $139 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. |
(c) | A reclassification of deferred tax assets from Total Assets of $488 million and $143 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. |
(d) | A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 6,515 |
| | $ | 6,614 |
| | $ | 6,383 |
| | $ | 6,499 |
| | $ | 6,011 |
|
Commercial | 5,439 |
| | 5,394 |
| | 5,317 |
| | 5,469 |
| | 5,214 |
|
Industrial | 3,262 |
| | 3,171 |
| | 3,172 |
| | 3,449 |
| | 3,188 |
|
Other | 114 |
| | 55 |
| | 115 |
| | 133 |
| | 128 |
|
Total retail | 15,330 |
| | 15,234 |
| | 14,987 |
| | 15,550 |
| | 14,541 |
|
Wholesale | 2,426 |
| | 1,926 |
| | 1,798 |
| | 2,184 |
| | 1,855 |
|
Total revenues from sales of electricity | 17,756 |
| | 17,160 |
| | 16,785 |
| | 17,734 |
| | 16,396 |
|
Natural gas revenues | 3,791 |
| | 1,596 |
| | — |
| | — |
| | — |
|
Other revenues | 1,484 |
| | 1,140 |
| | 704 |
| | 733 |
| | 691 |
|
Total | $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 50,536 |
| | 53,337 |
| | 52,121 |
| | 53,347 |
| | 50,575 |
|
Commercial | 52,340 |
| | 53,733 |
| | 53,525 |
| | 53,243 |
| | 52,551 |
|
Industrial | 52,785 |
| | 52,792 |
| | 53,941 |
| | 54,140 |
| | 52,429 |
|
Other | 846 |
| | 883 |
| | 897 |
| | 909 |
| | 902 |
|
Total retail | 156,507 |
| | 160,745 |
| | 160,484 |
| | 161,639 |
| | 156,457 |
|
Wholesale sales | 49,034 |
| | 37,043 |
| | 30,505 |
| | 32,786 |
| | 26,944 |
|
Total | 205,541 |
| | 197,788 |
| | 190,989 |
| | 194,425 |
| | 183,401 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.89 |
| | 12.40 |
| | 12.25 |
| | 12.18 |
| | 11.89 |
|
Commercial | 10.39 |
| | 10.04 |
| | 9.93 |
| | 10.27 |
| | 9.92 |
|
Industrial | 6.18 |
| | 6.01 |
| | 5.88 |
| | 6.37 |
| | 6.08 |
|
Total retail | 9.80 |
| | 9.48 |
| | 9.34 |
| | 9.62 |
| | 9.29 |
|
Wholesale | 4.95 |
| | 5.20 |
| | 5.89 |
| | 6.66 |
| | 6.88 |
|
Total sales | 8.64 |
| | 8.68 |
| | 8.79 |
| | 9.12 |
| | 8.94 |
|
Average Annual Kilowatt-Hour | | | | | | | | | |
Use Per Residential Customer | 11,618 |
| | 12,387 |
| | 13,318 |
| | 13,765 |
| | 13,144 |
|
Average Annual Revenue | | | | | | | | | |
Per Residential Customer | $ | 1,498 |
| | $ | 1,541 |
| | $ | 1,630 |
| | $ | 1,679 |
| | $ | 1,562 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 46,936 |
| | 46,291 |
| | 44,223 |
| | 46,549 |
| | 45,502 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 31,956 |
| | 32,272 |
| | 36,794 |
| | 37,234 |
| | 27,555 |
|
Summer | 34,874 |
| | 35,781 |
| | 36,195 |
| | 35,396 |
| | 33,557 |
|
System Reserve Margin (at peak) (percent)(b) | 30.8 |
| | 34.2 |
| | 33.2 |
| | 19.8 |
| | 21.5 |
|
Annual Load Factor (percent) | 61.4 |
| | 61.5 |
| | 59.9 |
| | 59.6 |
| | 63.2 |
|
Plant Availability (percent): | | | | | | | | | |
Fossil-steam | 84.5 |
| | 86.4 |
| | 86.1 |
| | 85.8 |
| | 87.7 |
|
Nuclear | 94.7 |
| | 93.3 |
| | 93.5 |
| | 91.5 |
| | 91.5 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 27.0 |
| | 30.3 |
| | 32.3 |
| | 39.3 |
| | 36.9 |
|
Nuclear | 14.5 |
| | 14.5 |
| | 15.2 |
| | 14.8 |
| | 15.5 |
|
Oil and gas | 41.9 |
| | 41.7 |
| | 42.7 |
| | 37.0 |
| | 37.2 |
|
Hydro | 2.1 |
| | 2.1 |
| | 2.6 |
| | 2.5 |
| | 3.9 |
|
Other | 5.4 |
| | 2.4 |
| | 0.8 |
| | 0.4 |
| | 0.1 |
|
Purchased power | 9.1 |
| | 9.0 |
| | 6.4 |
| | 6.0 |
| | 6.4 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Gas Sales Volumes (mmBtu in millions): | | | | | | | | | |
Firm | 667 |
| | 296 |
| | — |
| | — |
| | — |
|
Interruptible | 95 |
| | 53 |
| | — |
| | — |
| | — |
|
Total | 762 |
| | 349 |
| | — |
| | — |
| | — |
|
Traditional Electric Operating Company Customers (year-end) (in thousands): | | | | | | | | | |
Residential | 4,011 |
| | 3,970 |
| | 3,928 |
| | 3,890 |
| | 3,859 |
|
Commercial(b) | 599 |
| | 595 |
| | 590 |
| | 586 |
| | 582 |
|
Industrial(b) | 18 |
| | 17 |
| | 17 |
| | 17 |
| | 17 |
|
Other | 12 |
| | 11 |
| | 11 |
| | 11 |
| | 9 |
|
Total electric customers | 4,640 |
| | 4,593 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Gas distribution operations customers | 4,623 |
| | 4,586 |
| | — |
| | — |
| | — |
|
Total utility customers | 9,263 |
| | 9,179 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Employees (year-end) | 31,344 |
| | 32,015 |
| | 26,703 |
| | 26,369 |
| | 26,300 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of customers from commercial to industrial is reflected for years 2013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material. |
ALABAMA POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2017 Annual Report
The management of Alabama Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017.
/s/ Mark A. Crosswhite
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer
/s/ Philip C. Raymond
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Alabama Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the Company) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2017 and 2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-186 to II-231) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company provides electricityis not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 20, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
AFUDC | Allowance for funds used during construction |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
DOE | U.S. Department of Energy |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
NDR | Natural Disaster Reserve |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreement |
PSC | Public Service Commission |
Rate CNP | Rate Certificated New Plant |
Rate CNP Compliance | Rate Certificated New Plant Compliance |
Rate CNP PPA | Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Rate Energy Cost Recovery |
Rate NDR | Rate Natural Disaster Reserve |
Rate RSE | Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
Southern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2017 Annual Report
OVERVIEW
Business Activities
Alabama Power Company (the Company) operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns,
Many factors affect the opportunities, challenges, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, includingrisks of the Company's Plant Farley.
business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. The equity method is used for subsidiaries in whichCompany has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary.foreseeable future.
The Company is subject to regulation by the FERC and the Alabama PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the requirementsCompany's results and generally targets the top quartile of ASC 606. these surveys in measuring performance.
See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Earnings
The ultimateCompany's 2017 net income after dividends on preferred and preference stock was $848 million, representing a $26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.
The Company's 2016 net income after dividends on preferred and preference stock was $822 million, representing a $37 million, or 4.7%, increase over the new standard hasprevious year. The increase was due primarily to an increase in retail revenues under Rate CNP Compliance, an increase in weather-related revenues, and a decrease in operations and maintenance expenses not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to fuel or Rate CNP Compliance. These increases to income were partially offset by an accrual for a recognized debt liability be presentedRate RSE refund, a decrease in the balance sheet as a direct deduction from the carrying amount of that debt liabilityAFUDC equity, and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resultedan increase in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $39 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 10 for disclosures impacted by ASU 2015-03.depreciation.
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 for disclosures impacted by ASU 2015-07.
On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
adoptionRESULTS OF OPERATIONS
A condensed income statement for the Company follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 | | 2016 |
| (in millions) |
Operating revenues | $ | 6,039 |
| | $ | 150 |
| | $ | 121 |
|
Fuel | 1,225 |
| | (72 | ) | | (45 | ) |
Purchased power | 328 |
| | (6 | ) | | (17 | ) |
Other operations and maintenance | 1,652 |
| | 142 |
| | 9 |
|
Depreciation and amortization | 736 |
| | 33 |
| | 60 |
|
Taxes other than income taxes | 384 |
| | 4 |
| | 12 |
|
Total operating expenses | 4,325 |
| | 101 |
| | 19 |
|
Operating income | 1,714 |
| | 49 |
| | 102 |
|
Allowance for equity funds used during construction | 39 |
| | 11 |
| | (32 | ) |
Interest expense, net of amounts capitalized | 305 |
| | 3 |
| | 28 |
|
Other income (expense), net | (14 | ) | | 7 |
| | 11 |
|
Income taxes | 568 |
| | 37 |
| | 25 |
|
Net income | 866 |
| | 27 |
| | 28 |
|
Dividends on preferred and preference stock | 18 |
| | 1 |
| | (9 | ) |
Net income after dividends on preferred and preference stock | $ | 848 |
| | $ | 26 |
| | $ | 37 |
|
Operating Revenues
Operating revenues for 2017 were $6.0 billion, reflecting a $150 million increase from 2016. Details of ASU 2015-17, all deferred income tax assetsoperating revenues were as follows: |
| | | | | | | |
| Amount |
| 2017 | | 2016 |
| (in millions) |
Retail — prior year | $ | 5,322 |
| | $ | 5,234 |
|
Estimated change resulting from — | | | |
Rates and pricing | 362 |
| | 147 |
|
Sales decline | (44 | ) | | (20 | ) |
Weather | (89 | ) | | 31 |
|
Fuel and other cost recovery | (93 | ) | | (70 | ) |
Retail — current year | 5,458 |
| | 5,322 |
|
Wholesale revenues — | | | |
Non-affiliates | 276 |
| | 283 |
|
Affiliates | 97 |
| | 69 |
|
Total wholesale revenues | 373 |
| | 352 |
|
Other operating revenues | 208 |
| | 215 |
|
Total operating revenues | $ | 6,039 |
| | $ | 5,889 |
|
Percent change | 2.6 | % | | 2.1 | % |
Retail revenues in 2017 were $5.5 billion. These revenues increased $136 million, or 2.6%, in 2017 and liabilities were required$88 million, or 1.7%, in 2016, each as compared to be separated into currentthe prior year. The increase in 2017 was primarily due to an increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-current accumulated deferred income taxesmilder weather in the Company’s December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: generalfirst and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $438 million, $400 million, and $340 million during 2015, 2014, and 2013, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.third quarters 2017
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $243 million, $234 million, and $211 million during 2015, 2014, and 2013, respectively.
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $11 million in 2015, $13 million in 2014, and $13 million in 2013. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $8 million in 2015, $34 million in 2014, and $27 million in 2013. See Note 4 for additional information.
The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. The transmission improvements were completed in 2014. The Company received $14 million in 2015 and expects to recover approximately $12 million a year from 2016 through 2023 through a tariff with Gulf Power.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015, 2014, or 2013.
Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO.
The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Regulatory Assets and Liabilities
The Company is subjectas compared to the provisions of the FASBcorresponding periods in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected2016. The increase in 2016 was due to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductionsan increase in revenues associated with amounts that are expectedunder Rate CNP Compliance as a result of increased net investments, partially offset by a decrease in fuel revenues and an accrual for a Rate RSE refund. See Note 3 to be creditedthe financial statements under "Retail Regulatory Matters – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.
Fuel rates billed to customers throughare designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the ratemaking process.recording of revenues to offset fuel and purchased power expenses. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:Wholesale revenues from power sales to non-affiliated utilities were as follows:
|
| | | | | | | | | |
| 2015 |
| | 2014 |
| | Note |
| (in millions) | | |
Deferred income tax charges | $ | 522 |
| | $ | 525 |
| | (a,k) |
Loss on reacquired debt | 75 |
| | 80 |
| | (b) |
Vacation pay | 66 |
| | 65 |
| | (c,j) |
Under/(over) recovered regulatory clause revenues | (97 | ) | | 57 |
| | (d) |
Fuel-hedging losses | 55 |
| | 53 |
| | (e,j) |
Other regulatory assets | 53 |
| | 49 |
| | (f) |
Asset retirement obligations | (40 | ) | | (125 | ) | | (a) |
Other cost of removal obligations | (722 | ) | | (744 | ) | | (a) |
Deferred income tax credits | (70 | ) | | (72 | ) | | (a) |
Nuclear outage | 53 |
| | 56 |
| | (d) |
Natural disaster reserve | (75 | ) | | (84 | ) | | (h) |
Other regulatory liabilities | (8 | ) | | (17 | ) | | (e,g) |
Retiree benefit plans | 903 |
| | 882 |
| | (i,j) |
Remaining net book value of retired assets | 76 |
| | 13 |
| | (l) |
Total regulatory assets (liabilities), net | $ | 791 |
| | $ | 738 |
| | |
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Capacity and other | $ | 154 |
| | $ | 154 |
| | $ | 140 |
|
Energy | 122 |
| | 129 |
| | 101 |
|
Total non-affiliated | $ | 276 |
| | $ | 283 |
| | $ | 241 |
|
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized overWholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. |
| |
(b) | Recovered over the remaining life of the original issue, which may range up to 50 years. |
| |
(c) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(d) | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. |
| |
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. |
| |
(f) | Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. |
| |
(g) | Comprised of components including mine reclamation and remediation liabilities, fuel-hedging gains and nuclear fuel disposal fee. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. Nuclear fuel disposal fees are recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The balance was transferred to Rate ECR in 2015. See Note 3 for additional information. |
| |
(h) | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. |
| |
(i) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(k) | Included in the deferred income tax charges are $17 million for 2015 and $18 million for 2014 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. |
| |
(l) | Recorded and amortized as approved by the Alabama PSC for a period up to 11 years. |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rulesand the Southern Company system's generation, demand for rate regulation,energy within the Southern Company would be required to write off to income or reclassify to accumulated OCI related regulatory assetssystem's electric service territory, and liabilitiesavailability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not specifically recoverableaffect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy.
In 2017, wholesale revenues from sales to non-affiliates decreased $7 million, or 2.5%, as compared to the prior year. In 2016, wholesale revenues from sales to non-affiliates increased $42 million, or 17.4%, as compared to the prior year primarily due to a $28 million increase in revenues from energy sales and a $14 million increase in capacity revenues. In 2016, KWH sales increased 33.3% primarily due to a new contract that became effective in the first quarter 2016 partially offset by a 12.1% decrease in the price of energy due to lower natural gas prices.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through regulated rates. the Company's energy cost recovery clause.
In addition,2017, wholesale revenues from sales to affiliates increased $28 million, or 40.6%, as compared to the prior year. In 2017, KWH sales increased 31.1% as a result of supporting Southern Company would be requiredsystem transmission reliability and a 6.9% increase in the price of energy primarily due to determine if any impairmenthigher natural gas prices. In 2016, wholesale revenues from sales to other assets, including plant, existsaffiliates decreased $15 million, or 17.9%, as compared to the prior year. In 2016, KWH sales decreased 15.7% as a result of lower-cost generation available in the Southern Company system and write downa 2.6% decrease in the assets, if impaired,price of energy primarily due to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.lower natural gas prices.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Revenues
Wholesale capacityEnergy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:
|
| | | | | | | | | | | | | | |
| Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in billions) | | | | | | | | |
Residential | 17.2 |
| | (6.1 | )% | | 1.4 | % | | (1.2 | )% | | (0.5 | )% |
Commercial | 13.6 |
| | (3.4 | ) | | (0.1 | ) | | (1.3 | ) | | (0.5 | ) |
Industrial | 22.7 |
| | 1.7 |
| | (4.6 | ) | | 1.7 |
| | (4.6 | ) |
Other | 0.2 |
| | (5.0 | ) | | 3.8 |
| | (5.0 | ) | | 3.8 |
|
Total retail | 53.7 |
| | (2.3 | ) | | (1.5 | ) | | (0.1 | )% | | (2.2 | )% |
Wholesale | | | | | | | | | |
Non-affiliates | 5.5 |
| | (6.5 | ) | | 37.1 |
| | | | |
Affiliates | 4.2 |
| | 31.1 |
| | (15.7 | ) | | | | |
Total wholesale | 9.7 |
| | 6.6 |
| | 12.5 |
| | | | |
Total energy sales | 63.4 |
| | (1.0 | )% | | 0.3 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2017 were 2.3% lower than in 2016. Residential sales and commercial sales decreased 6.1% and 3.4% in 2017, respectively, primarily due to milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016. Weather-adjusted residential sales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales increased 1.7% in 2017 as compared to 2016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors offset by the pipelines and paper sectors.
Retail energy sales in 2016 were 1.5% lower than in 2015. Residential sales increased 1.4% primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015. Commercial sales remained flat in 2016. Weather-adjusted residential sales were flat in 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Industrial sales decreased 4.6% in 2016 compared to 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemical, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global growth conditions constrained growth in the industrial sector in 2016.
See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energysales to non-affiliates and otherwholesale revenues are recognizedfrom sales to affiliated companies as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuationschanges in fuel costs, fuel hedging, the energy component of purchased power costs,price and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information.
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.KWH sales.
Fuel Costsand Purchased Power Expenses
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortizationconstitute one of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel.
See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Company's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Generation | $ | 12,820 |
| | $ | 11,670 |
|
Transmission | 3,773 |
| | 3,579 |
|
Distribution | 6,432 |
| | 6,196 |
|
General | 1,713 |
| | 1,623 |
|
Plant acquisition adjustment | 12 |
| | 12 |
|
Total plant in service | $ | 24,750 |
| | $ | 23,080 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders.
Nuclear Outage Accounting Order
In accordance with an Alabama PSC order, nuclear outage operations and maintenancelargest expenses for the two units at Plant Farley are deferred to a regulatory asset whenCompany. The mix of fuel sources for generation of electricity is determined primarily by the charges actually occur and are then amortized over a subsequent 18-month period with the fall outage costs amortization beginning in Januaryunit cost of the following yearfuel consumed, demand, and the spring outage costs amortization beginning in Julyavailability of generating units. Additionally, the same year.Company purchases a portion of its electricity needs from the wholesale market.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2015, 3.3% in 2014 and 3.2% in 2013. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
In 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. The new rates resulted in the decrease in the composite depreciation rate for 2015.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17, 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.
Details of the AROs included in the balance sheets areCompany's generation and purchased power were as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Total generation (in billions of KWHs) | 60.3 |
| | 60.2 |
| | 60.9 |
|
Total purchased power (in billions of KWHs) | 6.4 |
| | 7.1 |
| | 6.3 |
|
Sources of generation (percent) — | | | | | |
Coal | 50 |
| | 53 |
| | 54 |
|
Nuclear | 24 |
| | 23 |
| | 24 |
|
Gas | 20 |
| | 19 |
| | 16 |
|
Hydro | 6 |
| | 5 |
| | 6 |
|
Cost of fuel, generated (in cents per net KWH) — | | | | | |
Coal | 2.60 |
| | 2.75 |
| | 2.83 |
|
Nuclear | 0.75 |
| | 0.78 |
| | 0.81 |
|
Gas | 2.72 |
| | 2.67 |
| | 2.94 |
|
Average cost of fuel, generated (in cents per net KWH)(a) | 2.14 |
| | 2.26 |
| | 2.34 |
|
Average cost of purchased power (in cents per net KWH)(b) | 5.29 |
| | 4.80 |
| | 5.66 |
|
|
| |
(a) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
(b) | Average cost of purchased power includes fuel, energy, and transmission purchased by the Company for tolling agreements where power is generated by the provider. |
|
| | | | | | | | | |
| 2015 | | | 2014 | |
| (in millions) | |
Balance at beginning of year | $ | 829 |
| | | $ | 730 |
| |
Liabilities incurred | 402 |
| | | 1 |
| |
Liabilities settled | (3 | ) | | | (3 | ) | |
Accretion | 53 |
| | | 45 |
| |
Cash flow revisions | 167 |
| | | 56 |
| |
Balance at end of year | $ | 1,448 |
| | | $ | 829 |
| |
Fuel and purchased power expenses were $1.55 billion in 2017, a decrease of $78 million, or 4.8%, compared to 2016. The increase in liabilities incurred and cash flow revisions in 2015 isdecrease was primarily due to a $67 million net decrease related to the Company's AROs associated withvolume of KWHs generated and purchased and a $42 million decrease in the impactaverage cost of fuel, partially offset by a $31 million increase in the CCR Rule on its ashaverage cost of purchased power.
Fuel and gypsum facilities.purchased power expenses were $1.63 billion in 2016, a decrease of $62 million, or 3.7%, compared to 2015. The decrease was primarily due to a $61 million decrease in the average cost estimates for AROsof purchased power, and a $59 million decrease in the average cost of fuel, partially offset by a $49 million increase related to the CCR Rulevolume of KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are basedgenerally offset by energy revenues through the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Energy purchases from non-affiliates will vary depending on informationthe market prices of wholesale energy as compared to the cost of December 31, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates,the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed, including evaluationavailability of the expected methodSouthern Company system's generation.
Fuel
Fuel expenses were $1.2 billion in 2017, a decrease of compliance, refinement$72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of assumptionsKWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas. Fuel expenses were $1.3 billion in 2016, a decrease of $45 million, or 3.4%, compared to 2015. The decrease was primarily due to a 9.2% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 4.2% and 3.9% decrease in the volume of KWHs generated by nuclear fuel and coal, respectively, and a 3.7% decrease in the average cost of KWHs generated by nuclear fuel, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.
Purchased Power – Affiliates
II-171Purchased power expense from affiliates was $158 million in 2017, a decrease of $10 million, or 6.0%, compared to 2016. This decrease was primarily due to a 17.2% decrease in the amount of energy purchased due to milder weather partially offset by a 13.9% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from affiliates was $168 million in 2016, a decrease of $12 million, or 6.7%, compared to 2015. This decrease was primarily due to a
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
underlying20.7% decrease in the average cost estimates, such asper KWH purchased due to lower natural gas prices, partially offset by a 17.5% increase in the quantitiesamount of CCR at each site, and the determination of timing, including the potential for closing ash ponds priorenergy purchased due to the endavailability of their currently anticipated useful life, the Company expects to continue to periodically update these estimates.
The cash flow revisions in 2014 are primarily relatedlower-cost generation compared to the Company's AROs associated with asbestosowned generation.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at its steam generation facilities.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Theeach company within the Southern Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Fundssystem. These purchases are managed and investedmade in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC,IIC or other contractual agreements, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
At December 31, 2015, investment securities in the Funds totaled $734 million, consisting of equity securities of $521 million, debt securities of $191 million, and $22 million of other securities. At December 31, 2014, investment securities in the Funds totaled $754 million, consisting of equity securities of $583 million, debt securities of $163 million, and $8 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases.
Sales of the securities held in the Funds resulted in cash proceeds of $438 million, $244 million, and $279 million in 2015, 2014, and 2013, respectively, all of which were reinvested. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million, which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million, which included $19 million related to unrealized gains on securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, which included $85 million related to unrealized losses on securities held in the Funds at December 31, 2013. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC.FERC.
Other Operations and Maintenance Expenses
In 2017, other operations and maintenance expenses increased $142 million, or 9.4%, as compared to the prior year. Distribution and transmission expenses increased $58 million primarily due to vegetation management expenses. Generation costs increased $38 million primarily due to outage costs. Employee benefit costs, including pension costs, increased $22 million.
In 2016, other operations and maintenance expenses increased $9 million, or 0.6%, as compared to the prior year. Steam production costs increased $28 million primarily due to the timing of generation operating expenses. Transmission and distribution expenses increased $10 million and $7 million, respectively, primarily due to additional vegetation management and other maintenance expenses. These increases were partially offset by a decrease of $32 million in employee benefit costs, including pension costs. The NRC's minimum external funding requirements are based onincreases in operations and maintenance expenses were primarily Rate CNP compliance-related costs and therefore had no significant impact to net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP Compliance" herein for additional information.
See Note 2 to the financial statements under "Pension Plans" for additional information.
Depreciation and Amortization
Depreciation and amortization increased $33 million, or 4.7%, in 2017 as compared to the prior year primarily due to additional plant in service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by a generic estimatedecrease in distribution-related depreciation rates. See Note 1 to the financial statements under "Depreciation and Amortization" for additional information. Depreciation and amortization increased $60 million, or 9.3%, in 2016 as compared to the prior year primarily due to compliance-related steam projects placed in service.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $4 million, or 1.1%, in 2017 as compared to the prior year. In 2016, taxes other than income taxes increased $12 million, or 3.3% in 2016 as compared to the prior year. The increase was primarily due to increases in state and municipal utility license tax bases primarily due to an increase in retail revenues. In addition, ad valorem taxes increased primarily due to an increase in assessed value of property.
Allowance for Equity Funds Used During Construction
AFUDC equity increased $11 million, or 39.3%, in 2017 as compared to the costprior year. The increase was primarily associated with steam, transmission, and nuclear construction projects. AFUDC equity decreased $32 million, or 53.3%, in 2016 as compared to decommission only the radioactive portionsprior year. The decrease was primarily associated with steam generation capital projects being placed in service. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $3 million, or 1.0%, in 2017 as compared to the prior year. Interest expense, net of amounts capitalized increased $28 million, or 10.2%, in 2016 as compared to the prior year primarily due to an increase in debt outstanding and a nuclear unit based onreduction in the size and typeamounts capitalized. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.
Other Income (Expense), Net
Other income (expense), net increased $7 million, or 33.3%, in 2017 as compared to the prior year primarily due to increases in unregulated lighting services. Other income (expense), net increased $11 million, or 34.4%, in 2016 as compared to the prior year primarily due to a decrease in donations, partially offset by a decrease in sales of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.non-utility property.
At December 31, the accumulated provisions for decommissioning were as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
External trust funds | $ | 734 |
| | $ | 754 |
|
Internal reserves | 20 |
| | 21 |
|
Total | $ | 754 |
| | $ | 775 |
|
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Site study costs is the estimate to decommission a facilityIncome Taxes
Income taxes increased $37 million, or 7.0%, in 2017 as of the site study year. The estimated costs of decommissioning as of December 31, 2015 based on the most current study performed in 2013 for Plant Farley are as follows:
|
| | | |
Decommissioning periods: | |
Beginning year | 2037 |
|
Completion year | 2076 |
|
| (in millions) |
Site study costs: | |
Radiated structures | $ | 1,362 |
|
Non-radiated structures | 80 |
|
Total site study costs | $ | 1,442 |
|
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2018.
Amounts previously contributedcompared to the Funds are currently projectedprior year primarily due to be adequatehigher pre-tax earnings, an increase in prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.7% in 2015, 8.8% in 2014, and 9.1% in 2013. AFUDC, net of income taxes as a percentresult of net income after dividendsTax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information. Income taxes increased $25 million, or 4.9%, in 2016 as compared to the prior year primarily due to higher pre-tax earnings.
Dividends on Preferred and Preference Stock
Dividends on preferred and preference stock increased $1 million, or 5.9%, in 2017 as compared to the prior year. Dividends on preferred and preference stock decreased $9 million, or 34.6%, in 2016 as compared to the prior year. The decrease was 9.3%primarily due to the redemption in May 2015, 7.9% in 2014, of certain series of preferred and 5.4% in 2013.preference stock. See Note 6 to the financial statements under "Redeemable Preferred and Preference Stock" for additional information.
ImpairmentEffects of Long-Lived Assets and IntangiblesInflation
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicateis subject to rate regulation that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is generally based on either a specific regulatory disallowance orthe recovery of historical and projected costs. The effects of inflation can create an estimateeconomic loss since the recovery of undiscounted future cash flows attributablecosts could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Cash and Cash Equivalents
For purposes of the financial statements temporary cash investmentsunder "Retail Regulatory Matters – Rate RSE" for additional information.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama and to wholesale customers in the Southeast. Prices for electric service provided by the Company to retail customers are considered cash equivalents. Temporary cash investmentsset by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electric service, interconnecting transmission lines, and the exchange of electric power are securities with original maturitiesregulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of 90 days or less.Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.
MaterialsThe results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and Supplies
Generally, materials and suppliesrisks of the Company's primary business of providing electric service. These factors include the average costCompany's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of transmission, distribution,prudently-incurred costs during a time of increasing costs and generating plant materials. Materialslimited projected demand growth over the next several years. Future earnings will be impacted by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are chargedsubject to inventory when purchaseda variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and then expensedthe rate of economic growth or capitalizeddecline in the Company's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to plant, as appropriate, at weighted average cost when installed.21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Fuel Inventory
Fuel inventory includesflows, and financial condition. Compliance costs may result from the averageinstallation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of coal, natural gas, oil, transportation,any deployed control technology, and emissions allowances. Fuel is charged to inventory when purchasedthe outcome of pending and/or future legal challenges.
New or revised environmental laws and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially allregulations could affect many areas of the Company's bulk energy purchasesoperations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate CNP Compliance" for additional information. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and sales contracts that meetfinancial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the definitionpotential to ultimately affect their demand for electricity.
Through 2017, the Company has invested approximately $4.7 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of a derivativeapproximately $491 million, $260 million, and $349 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are excludedadopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.4 billion from fair value accounting requirements because they qualify2018 through 2022, with annual totals of approximately $581 million in 2018, $110 million in 2019, $163 million in 2020, $258 million in 2021, and $268 million in 2022. These estimates do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for the "normal" scope exception,additional information. The Company also anticipates expenditures associated with ash pond closure and are accounted forground water monitoring under the accrual method. Derivative contracts that qualify as cash flow hedgesDisposal of anticipated transactionsCoal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2015, the EPA published a more stringent eight-hour ozone NAAQS. The EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are recoverable throughanticipated to be designated nonattainment under the Alabama PSC-approved fuel-hedging program result2015 ozone NAAQS. In 2010, the EPA revised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the deferralvicinity of related gainsCompany-owned SO2 sources have been designated nonattainment under the 2010 one-hour SO2 NAAQS. However, final eight-hour ozone and losses in OCI or regulatory assetsSO2 one-hour designations for certain areas are still pending and, liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualifyif other areas are designated as fair value hedges are marked to market through current period income and are recorded on a net basisnonattainment in the statementsfuture, increased compliance costs could result.
In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that addresses the impacts of income. Cash flowsthe interstate transport of SO2 and NOX emissions from derivatives are classified on the statement of cash flowsfossil fuel-fired power plants located in upwind states in the same category aseastern half of the hedged item. See Note 11 for additional information regarding derivatives.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015.
The Company is exposed to losses related to financial instrumentsU.S. on air quality in the event of counterparties' nonperformance.downwind states. The Company has established controlsfossil fuel-fired generation subject to determine and monitorthese requirements. In October 2016, the creditworthiness of counterpartiesEPA published a final rule that revised the CSAPR seasonal NOX program, establishing more stringent NOX emissions budgets in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changesAlabama. Increases in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losseseither future fossil fuel-fired generation or the rightcost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, and various federal agencies to receive benefits fromdevelop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the VIE that could potentially be significantgoal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States must submit a revised state implementation plan (SIP) to the VIE.
The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiaryEPA by July 31, 2021, demonstrating reasonable progress towards achieving visibility improvement goals. State implementation of the trust. Therefore, the investmentreasonable progress could require further reductions in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debtSO2 or NOX emissions, which could result in the balance sheets.increased compliance costs.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015, and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2016, no other postretirement trusts contributions are expected.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
Actuarial Assumptions
In 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs regulating excess emissions at industrial facilities, including electric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The weighted average rates assumedstate excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in the actuarial calculations used to determine both the net periodicincreased operations and maintenance costs for the pension and other postretirement benefit plans forCompany.
Water Quality
In 2014, the following year and the benefit obligations asEPA finalized requirements under Section 316(b) of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2015 |
| 2014 |
| 2013 |
Pension plans | | | | | |
Discount rate – interest costs | 4.18 | % | | 5.02 | % | | 4.27 | % |
Discount rate – service costs | 4.49 |
| | 5.02 |
| | 4.27 |
|
Expected long-term return on plan assets | 8.20 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – interest costs | 4.04 | % | | 4.86 | % | | 4.06 | % |
Discount rate – service costs | 4.40 |
| | 4.86 |
| | 4.06 |
|
Expected long-term return on plan assets | 7.17 |
| | 7.34 |
| | 7.36 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
|
| | | | | |
Assumptions used to determine benefit obligations: | 2015 |
| 2014 |
Pension plans |
|
|
|
Discount rate | 4.67 | % |
| 4.18 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
|
Other postretirement benefit plans |
|
|
|
Discount rate | 4.51 | % |
| 4.04 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
|
The Company estimates the expected rate of return on pension planClean Water Act (CWA) to regulate cooling water intake structures at existing power plants and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classesmanufacturing facilities in order to arrive at the expected returnminimize their effects on fish and other aquatic life. The regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the entire portfolio relyingintake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each trust's target asset allocation and reasonable capital market assumptions. The financial model isplant's National Pollutant Discharge Elimination System (NPDES) permit based on four key inputs: anticipated returnssite-specific factors.
In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020. The Company continues to monitor the ELG rule and anticipates that approximately 1,000 MWs of the Company's generation will not be available after the compliance date. The ultimate impact of this rule will depend on any new rule-making that revises the limitation and applicable dates. The Company does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on the Company's operations or financial condition.
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by asset class (basedthe U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
Coal Combustion Residuals
In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule requires CCR units to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.
The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule.
Based on historical returns), each trust's target asset allocation, an anticipated inflation rate,cost estimates for closure in place and monitoring of ash ponds pursuant to the projected impact of a periodic rebalancing of each trust's portfolio.
For purposes of its December 31, 2015 measurement date,CCR Rule, the Company adopted new mortality tablesrecorded AROs for its pensioneach CCR unit in 2015. As further analysis is performed and other postretirement benefit plans, which reflect decreased life expectancies inclosure details are developed, the U.S. The adoptionCompany will continue to periodically update these cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of new mortality tables reduced the projected benefit obligationsRemoval" for additional information regarding the Company's pension plans and other postretirement benefit plans by approximately $51 million and $9 million, respectively.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBOAROs as of December 31, 2015 were as follows:2017.
|
| | | | | | | | |
| | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | | 6.50 | % | | 4.50 | % | | 2024 |
Post-65 medical | | 5.50 |
| | 4.50 |
| | 2024 |
Post-65 prescription | | 10.00 |
| | 4.50 |
| | 2025 |
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 20152017 Annual Report
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2015 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 29 |
| | $ | (25 | ) |
Service and interest costs | 1 |
| | (1 | ) |
Pension Plans
The total accumulated benefit obligation for the pension plans was $2.3 billion at December 31, 2015 and $2.4 billion at December 31, 2014. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 2,592 |
| | $ | 2,112 |
|
Service cost | 59 |
| | 48 |
|
Interest cost | 106 |
| | 103 |
|
Benefits paid | (120 | ) | | (100 | ) |
Actuarial loss (gain) | (131 | ) | | 429 |
|
Balance at end of year | 2,506 |
| | 2,592 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 2,396 |
| | 2,278 |
|
Actual return (loss) on plan assets | (9 | ) | | 207 |
|
Employer contributions | 12 |
| | 11 |
|
Benefits paid | (120 | ) | | (100 | ) |
Fair value of plan assets at end of year | 2,279 |
| | 2,396 |
|
Accrued liability | $ | (227 | ) | | $ | (196 | ) |
At December 31, 2015, the projected benefit obligations for the qualified and non-qualified pension plans were $2.4 billion and $124 million, respectively. All pension plan assets are related to the qualified pension plan.
Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 822 |
| | $ | 827 |
|
Other current liabilities | (11 | ) | | (10 | ) |
Employee benefit obligations | (216 | ) | | (186 | ) |
Presented below are the amounts included in regulatory assets at December 31, 2015 and 2014 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2016.
NOTES (continued)
Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | |
| 2015 | | 2014 | | Estimated Amortization in 2016 |
| (in millions) |
Prior service cost | $ | 6 |
| | $ | 12 |
| | $ | 3 |
|
Net (gain) loss | 816 |
| | 815 |
| | 40 |
|
Regulatory assets | $ | 822 |
| | $ | 827 |
| | |
Global Climate IssuesThe changes inIn 2015, the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Regulatory assets: | | | |
Beginning balance | $ | 827 |
| | $ | 476 |
|
Net (gain) loss | 56 |
| | 389 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (6 | ) | | (7 | ) |
Amortization of net gain (loss) | (55 | ) | | (31 | ) |
Total reclassification adjustments | (61 | ) | | (38 | ) |
Total change | (5 | ) | | 351 |
|
Ending balance | $ | 822 |
| | $ | 827 |
|
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Service cost | $ | 59 |
| | $ | 48 |
| | $ | 52 |
|
Interest cost | 106 |
| | 103 |
| | 93 |
|
Expected return on plan assets | (178 | ) | | (168 | ) | | (157 | ) |
Recognized net loss | 55 |
| | 31 |
| | 52 |
|
Net amortization | 6 |
| | 7 |
| | 7 |
|
Net periodic pension cost | $ | 48 |
| | $ | 21 |
| | $ | 47 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Alabama Power Company 2015 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2015, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2016 | $ | 114 |
|
2017 | 119 |
|
2018 | 124 |
|
2019 | 129 |
|
2020 | 134 |
|
2021 to 2025 | 740 |
|
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 503 |
| | $ | 431 |
|
Service cost | 6 |
| | 5 |
|
Interest cost | 20 |
| | 20 |
|
Benefits paid | (27 | ) | | (27 | ) |
Actuarial loss (gain) | (7 | ) | | 71 |
|
Plan amendment | 7 |
| | — |
|
Retiree drug subsidy | 3 |
| | 3 |
|
Balance at end of year | 505 |
| | 503 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 392 |
| | 389 |
|
Actual return (loss) on plan assets | (6 | ) | | 23 |
|
Employer contributions | 1 |
| | 4 |
|
Benefits paid | (24 | ) | | (24 | ) |
Fair value of plan assets at end of year | 363 |
| | 392 |
|
Accrued liability | $ | (142 | ) | | $ | (111 | ) |
Amounts recognized in the balance sheets at December 31, 2015 and 2014 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 95 |
| | $ | 68 |
|
Other regulatory liabilities, deferred | (13 | ) | | (14 | ) |
Employee benefit obligations | (142 | ) | | (111 | ) |
NOTES (continued)
Alabama Power Company 2015 Annual Report
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2015 and 2014 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2016.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | Estimated Amortization in 2016 |
| (in millions) |
Prior service cost | $ | 19 |
| | $ | 15 |
| | $ | 4 |
|
Net (gain) loss | 63 |
| | 39 |
| | 2 |
|
Net regulatory assets | $ | 82 |
| | $ | 54 |
| | |
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2015 and 2014 are presented in the following table:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Net regulatory assets (liabilities): | | | |
Beginning balance | $ | 54 |
| | $ | (15 | ) |
Net (gain) loss | 25 |
| | 73 |
|
Change in prior service costs | 8 |
| | — |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (3 | ) | | (4 | ) |
Amortization of net gain (loss) | (2 | ) | | — |
|
Total reclassification adjustments | (5 | ) | | (4 | ) |
Total change | 28 |
| | 69 |
|
Ending balance | $ | 82 |
| | $ | 54 |
|
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Service cost | $ | 6 |
| | $ | 5 |
| | $ | 6 |
|
Interest cost | 20 |
| | 20 |
| | 19 |
|
Expected return on plan assets | (26 | ) | | (25 | ) | | (23 | ) |
Net amortization | 5 |
| | 4 |
| | 5 |
|
Net periodic postretirement benefit cost | $ | 5 |
| | $ | 4 |
| | $ | 7 |
|
NOTES (continued)
Alabama Power Company 2015 Annual Report
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2016 | $ | 33 |
| | $ | (3 | ) | | $ | 30 |
|
2017 | 34 |
| | (3 | ) | | 31 |
|
2018 | 34 |
| | (3 | ) | | 31 |
|
2019 | 35 |
| | (4 | ) | | 31 |
|
2020 | 36 |
| | (4 | ) | | 32 |
|
2021 to 2025 | 184 |
| | (20 | ) | | 164 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2015 and 2014, along with the targeted mix of assets for each plan, is presented below:
|
| | | | | | | | |
| Target | | 2015 | | 2014 |
Pension plan assets: | | | | | |
Domestic equity | 26 | % | | 30 | % | | 30 | % |
International equity | 25 |
| | 23 |
| | 23 |
|
Fixed income | 23 |
| | 23 |
| | 27 |
|
Special situations | 3 |
| | 2 |
| | 1 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
|
Private equity | 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | |
Domestic equity | 48 | % | | 45 | % | | 48 | % |
International equity | 20 |
| | 20 |
| | 20 |
|
Domestic fixed income | 24 |
| | 27 |
| | 26 |
|
Special situations | 1 |
| | 1 |
| | — |
|
Real estate investments | 4 |
| | 5 |
| | 4 |
|
Private equity | 3 |
| | 2 |
| | 2 |
|
Total | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a
NOTES (continued)
Alabama Power Company 2015 Annual Report
formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2015 and 2014. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
Real estate investments and private equity.Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
NOTES (continued)
Alabama Power Company 2015 Annual Report
The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 403 |
| | $ | 168 |
| | $ | — |
| | $ | — |
| | $ | 571 |
|
International equity* | 294 |
| | 244 |
| | — |
| | — |
| | 538 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 112 |
| | — |
| | — |
| | 112 |
|
Mortgage- and asset-backed securities | — |
| | 49 |
| | — |
| | — |
| | 49 |
|
Corporate bonds | — |
| | 280 |
| | — |
| | — |
| | 280 |
|
Pooled funds | — |
| | 123 |
| | — |
| | — |
| | 123 |
|
Cash equivalents and other | — |
| | 36 |
| | — |
| | — |
| | 36 |
|
Real estate investments | 74 |
| | — |
| | — |
| | 301 |
| | 375 |
|
Private equity | — |
| | — |
| | — |
| | 157 |
| | 157 |
|
Total | $ | 771 |
| | $ | 1,012 |
| | $ | — |
| | $ | 458 |
| | $ | 2,241 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 421 |
| | $ | 174 |
| | $ | — |
| | $ | — |
| | $ | 595 |
|
International equity* | 264 |
| | 244 |
| | — |
| | — |
| | 508 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 173 |
| | — |
| | — |
| | 173 |
|
Mortgage- and asset-backed securities | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
Corporate bonds | — |
| | 280 |
| | — |
| | — |
| | 280 |
|
Pooled funds | — |
| | 127 |
| | — |
| | — |
| | 127 |
|
Cash equivalents and other | 1 |
| | 163 |
| | — |
| | — |
| | 164 |
|
Real estate investments | 73 |
| | — |
| | — |
| | 277 |
| | 350 |
|
Private equity | — |
| | — |
| | — |
| | 141 |
| | 141 |
|
Total | $ | 759 |
| | $ | 1,208 |
| | $ | — |
| | $ | 418 |
| | $ | 2,385 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
NOTES (continued)
Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 57 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 65 |
|
International equity* | 14 |
| | 12 |
| | — |
| | — |
| | 26 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Mortgage- and asset-backed securities | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Corporate bonds | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
Pooled funds | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Cash equivalents and other | 1 |
| | 2 |
| | — |
| | — |
| | 3 |
|
Trust-owned life insurance | — |
| | 212 |
| | — |
| | — |
| | 212 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 14 |
| | 19 |
|
Private equity | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
Total | $ | 77 |
| | $ | 263 |
| | $ | — |
| | $ | 21 |
| | $ | 361 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 76 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 84 |
|
International equity* | 13 |
| | 12 |
| | — |
| | — |
| | 25 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Mortgage- and asset-backed securities | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Corporate bonds | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Pooled funds | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Cash equivalents and other | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Trust-owned life insurance | — |
| | 217 |
| | — |
| | — |
| | 217 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 13 |
| | 18 |
|
Private equity | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
Total | $ | 94 |
| | $ | 277 |
| | $ | — |
| | $ | 20 |
| | $ | 391 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2015, 2014, and 2013 were $22 million, $21 million, and $20 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused byEPA published final rules limiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO2emissions CCR,rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, alleged exposureon December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.
In 2015, parties to hazardous materials, and/or requeststhe United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for injunctive relief in connection with such matters.addressing greenhouse gas (GHG) emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate outcomeimpact of such pendingthis agreement or potential litigation againstany renegotiated agreement depends on its implementation by participating countries.
The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate thatCompany's 2016 GHG emissions were approximately 38 million metric tons of CO2 equivalent. The preliminary estimate of the ultimate liabilities, if any, arising from such current proceedings would have a material effectCompany's 2017 GHG emissions on the Company's financial statements.
Environmental Matters
Environmental Remediation
The Company must comply with environmental laws and regulations that cover the handling and disposalsame basis is approximately 37 million metric tons of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year
NOTES (continued)
Alabama Power Company 2015 Annual Report
presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.
In December 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19, 2015, the Company recovered approximately $26 million. In November 2015, the Company applied the retail-related proceeds to offset the nuclear fuel expense under Rate ECR. See "Retail Regulatory Matters – Nuclear Waste Fund Accounting Order" herein for additional information. In December 2015, the Company credited the wholesale-related proceeds to each wholesale customer.
In March 2014, the Company filed an additional lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for any potential recoveries from this lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected.
At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant.CO2 equivalent.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Retail Regulatory Matters
The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. The Company currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting the Company. See Note 1 to the financial statements and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's rate mechanisms and accounting orders.
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21%. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, customer refundsthe excess will be required;refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In 2013, theaccordance with an Alabama PSC approved a revisionorder issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE effective for calendar year 2014. This revision establishedincreased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range of 5.75% to 6.21% with an adjusting point of 5.98% and provided eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
The Rate RSE increase for 2015 was 3.49% or $181 million annually, and was effective Januaryrange. On December 1, 2015. On November 30, 2015,2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2016.2018. Projected earnings were within the specified WCE range; therefore, retail rates under Rate RSE remained unchanged for 2016.2018.
NOTES (continued)
Alabama Power Company 2015 Annual Report
Rate CNP PPA
The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service under Rate CNP.service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 3, 2015,7, 2017, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 20152017 through March 31, 2016.2018. No adjustment to Rate CNP PPA is expected in 2016. As of2018.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2015,2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company had anutilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovered certificated PPA balancerecovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of $99 millionthe new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is included in deferred under recovered regulatory clause revenues inexpected to occur within the balance sheet.next two to four years. The Company's current depreciation study became effective January 1, 2017.
Rate CNP Environmental allowedCompliance
Rate CNP Compliance allows for the recovery of the Company's retail costs associated with environmental laws, regulations, and other such mandates. On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. The Company was limited to recover $50 million of non-environmental compliance costs for the year 2015. Additional non-environmental compliance costs were recovered through Rate RSE. Customer rates were not impacted by this order in 2015; therefore, the modification increased the under recovered position for Rate CNP Compliance during 2015. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital.
Revenues for Rate CNP Compliance, increased 1.5%,as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or $75net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million annually,of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2015. As of2017.
On December 31, 2015,5, 2017, the Alabama PSC issued a consent order that the Company had anleave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered compliance clause balance of $43 million, which is included in under recovered regulatory clause revenuesamounts associated with 2018 will be reflected in the balance sheet.2019 filing.
Rate ECR
The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
On December 2014,5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 20152018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of 2.681January 1, 2018 remained at 2.015 cents per KWH.
On December 1, 2015, the Alabama PSC approved a decrease in the Company’s Rate ECR factor from 2.681 to 2.030 cents per KWH, 6.7%, or $370 million annually, based upon projected billings, effective January 1, 2016. The approved decrease in the Rate ECR factor will have no significant effect on the Company's net income, but will decrease operating cash flows related to fuel cost recovery in 2016 when compared to 2015. The rate will return to 2.681 cents per KWH in 2017 and 5.910 cents per KWH in 2018,2019, absent a further order from the Alabama PSC.
Rate NDR
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The Company'sorder approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over recovered fuel costsa 24-month period.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2015 totaled $238 million2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as comparedestablished prior to $47 million atthe decision regarding early retirement through Rate CNP Compliance. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2014. At2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2015, $2382017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $3 million, is includeda $271 million decrease in otherregulatory assets, and a $2.0 billion increase in regulatory liabilities, current. primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The over recovered fuel costs at December 31, 2014 are included in deferred over recoveredTax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand,treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the priceAlabama PSC. On January 31, 2018, SCS, on behalf of energy. A change in anythe traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters – Rate RSE" for additional information.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Federal Tax Reform Legislation" for additional information.
The ultimate outcome of these factorsmatters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, approximately $200 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year and approximately $90 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $24 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in an $9 million or less change in total annual benefit expense and a $128 million or less change in projected obligations.
The Company recorded pension costs of $9 million, $11 million, and $48 million in 2017, 2016, and 2015, respectively. Postretirement benefit costs for the Company were $3 million, $4 million, and $5 million in 2017, 2016, and 2015, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and other postretirement benefit costs is capitalized based on construction-related labor charges. Pension and other postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
investing activities include investments to meet projected long-term demand requirements, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, or equity contributions from Southern Company. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated during 2018. The Company's funding obligations for the nuclear decommissioning trust fund are based on the most recent site study, and the next study is expected to be conducted in 2018. See Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities totaled $1.8 billion for 2017, a decrease of $112 million as compared to 2016. The decrease in cash provided from operating activities was primarily due to the timing of income tax payments in 2017 and the receipt of income tax refunds in 2016 as a result of bonus depreciation, partially offset by the voluntary contribution to the qualified pension plan in 2016. Net cash provided from operating activities totaled $1.9 billion for 2016, a decrease of $193 million as compared to 2015. The decrease in cash provided from operating activities was primarily due to the collection of fuel cost recovery revenues and the voluntary contribution to the qualified pension plan, partially offset by the timing of income tax payments and refunds associated with bonus depreciation.
Net cash used for investing activities totaled $1.9 billion for 2017, $1.4 billion for 2016, and $1.5 billion for 2015. These activities were primarily related to gross property additions for environmental, steam generation, distribution, and transmission assets.
Net cash provided from financing activities totaled $163 million in 2017 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and maturities of long-term debt. Net cash used for financing activities totaled $285 million in 2016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by issuances of long-term debt and additional capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for 2017 included increases of $1.3 billion in property, plant, and equipment primarily due to additions to distribution and transmission facilities and environmental and steam generation assets and $1.1 billion in long-term debt. Other significant changes included an increase of $2.0 billion in deferred credits related to income taxes and decreases of $1.9 billion in accumulated deferred income taxes primarily due to the change in tax rate resulting from Tax Reform Legislation and $0.6 billion in securities due within one year. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
The Company's ratio of common equity to total capitalization plus short-term debt was 46.3% and 46.2% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.
Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
The Company's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At December 31, 2017, the Company had approximately $544 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Expires | | | | | | Expires Within One Year |
2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) |
$ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In May 2017 and September 2017, the Company amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
Most of these bank credit arrangements, as well as the Company's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of the Company. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $854 million as of December 31, 2017. In addition, at December 31, 2017, the Company had $120 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
The Company also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. The Company may meet short-term cash needs through its commercial paper program. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 3 |
| | 3.7 | % | | $ | 25 |
| | 1.3 | % | | $ | 223 |
|
December 31, 2016 | $ | — |
| | — | % | | $ | 16 |
| | 0.6 | % | | $ | 200 |
|
December 31, 2015 | $ | — |
| | — | % | | $ | 14 |
| | 0.2 | % | | $ | 100 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015. |
The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Financing Activities
In February 2017, the Company repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, the Company issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
In September 2017, the Company issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including the Company's continuous construction program.
In October 2017, the Company repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes.
In November 2017, the Company issued $550 million aggregate principal amount of Series 2017B 3.70% Senior Notes due December 1, 2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
At December 31, 2017, the Company did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 1 |
|
At BBB- and/or Baa3 | $ | 2 |
|
Below BBB- and/or Baa3 | $ | 323 |
|
Included in these amounts are certain agreements that could require collateral in the event that either the Company or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
On January 19, 2018, Moody's revised its rating outlook for the Company from stable to negative.
While it is unclear how the credit rating agencies and regulatory authorities may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure at December 31, 2017 was 2.3%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $11 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of the Company's natural gas budget for that year.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | 12 |
| | $ | (54 | ) |
Contracts realized or settled | (1 | ) | | 39 |
|
Current period changes(*) | (17 | ) | | 27 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (6 | ) | | $ | 12 |
|
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:
|
| | | | | |
| 2017 | | 2016 |
| mmBtu Volume |
| (in millions) |
Commodity – Natural gas swaps | 64 |
| | 68 |
|
Commodity – Natural gas options | 5 |
| | 6 |
|
Total hedge volume | 69 |
| | 74 |
|
The weighted average swap contract cost above market prices was approximately $0.08 per mmBtu as of December 31, 2017 and below market prices was approximately $0.14 per mmBtu as of December 31, 2016. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the natural gas hedge gains and losses are recovered through the Company's retail energy cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or returnfail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are primarily Level 2 of the fair value hierarchy, at December 31, 2017 were as follows:
|
| | | | | | | | | | | |
| | | Fair Value Measurements |
| | | December 31, 2017 |
| Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 |
| (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | 6 |
| | 4 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | 6 |
| | $ | 4 |
| | $ | 2 |
|
The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel costs.and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $581 million for 2018, $110 million for 2019, $163 million for 2020, $258 million for 2021, and $268 million for 2022. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.3 million for 2018, $111 million for 2019, $90 million for 2020, $94 million for 2021, and $96 million for 2022. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
As a result of NRC requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other postretirement benefit plans, preferred stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | — |
| | $ | 450 |
| | $ | 1,060 |
| | $ | 6,176 |
| | $ | 7,686 |
|
Interest | 304 |
| | 598 |
| | 561 |
| | 4,408 |
| | 5,871 |
|
Preferred stock dividends(b) | 15 |
| | 29 |
| | 29 |
| | — |
| | 73 |
|
Financial derivative obligations(c) | 6 |
| | 4 |
| | — |
| | — |
| | 10 |
|
Operating leases(d) | 21 |
| | 40 |
| | 24 |
| | 20 |
| | 105 |
|
Capital Lease | 1 |
| | 1 |
| | 1 |
| | 2 |
| | 5 |
|
Purchase commitments — | | | | | | | | | |
Capital(e) | 2,053 |
| | 2,972 |
| | 2,914 |
| | — |
| | 7,939 |
|
Fuel(f) | 974 |
| | 1,197 |
| | 459 |
| | 238 |
| | 2,868 |
|
Purchased power(g) | 78 |
| | 171 |
| | 186 |
| | 606 |
| | 1,041 |
|
Other(h) | 47 |
| | 73 |
| | 59 |
| | 313 |
| | 492 |
|
Pension and other postretirement benefit plans(i) | 19 |
| | 36 |
| | — |
| | — |
| | 55 |
|
Total | $ | 3,518 |
| | $ | 5,571 |
| | $ | 5,293 |
| | $ | 11,763 |
| | $ | 26,145 |
|
| |
(a) | All amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and are included in purchased power. |
| |
(e) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information. |
| |
(f) | Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(g) | Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. |
| |
(h) | Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;
investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Retail revenues | $ | 5,458 |
| | $ | 5,322 |
| | $ | 5,234 |
|
Wholesale revenues, non-affiliates | 276 |
| | 283 |
| | 241 |
|
Wholesale revenues, affiliates | 97 |
| | 69 |
| | 84 |
|
Other revenues | 208 |
| | 215 |
| | 209 |
|
Total operating revenues | 6,039 |
| | 5,889 |
| | 5,768 |
|
Operating Expenses: | | | | | |
Fuel | 1,225 |
| | 1,297 |
| | 1,342 |
|
Purchased power, non-affiliates | 170 |
| | 166 |
| | 171 |
|
Purchased power, affiliates | 158 |
| | 168 |
| | 180 |
|
Other operations and maintenance | 1,652 |
| | 1,510 |
| | 1,501 |
|
Depreciation and amortization | 736 |
| | 703 |
| | 643 |
|
Taxes other than income taxes | 384 |
| | 380 |
| | 368 |
|
Total operating expenses | 4,325 |
| | 4,224 |
| | 4,205 |
|
Operating Income | 1,714 |
| | 1,665 |
| | 1,563 |
|
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 39 |
| | 28 |
| | 60 |
|
Interest expense, net of amounts capitalized | (305 | ) | | (302 | ) | | (274 | ) |
Other income (expense), net | (14 | ) | | (21 | ) | | (32 | ) |
Total other income and (expense) | (280 | ) | | (295 | ) | | (246 | ) |
Earnings Before Income Taxes | 1,434 |
| | 1,370 |
| | 1,317 |
|
Income taxes | 568 |
| | 531 |
| | 506 |
|
Net Income | 866 |
| | 839 |
| | 811 |
|
Dividends on Preferred and Preference Stock | 18 |
| | 17 |
| | 26 |
|
Net Income After Dividends on Preferred and Preference Stock | $ | 848 |
| | $ | 822 |
| | $ | 785 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $(1), $(1), and $(3), respectively | 1 |
| | (2 | ) | | (5 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $1, respectively | 3 |
| | 4 |
| | 2 |
|
Total other comprehensive income (loss) | 4 |
| | 2 |
| | (3 | ) |
Comprehensive Income | $ | 870 |
| | $ | 841 |
| | $ | 808 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report |
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 888 |
| | 844 |
| | 780 |
|
Deferred income taxes | 409 |
| | 407 |
| | 388 |
|
Allowance for equity funds used during construction | (39 | ) | | (28 | ) | | (60 | ) |
Pension and postretirement funding | (2 | ) | | (133 | ) | | — |
|
Other, net | (14 | ) | | (102 | ) | | 15 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (168 | ) | | 94 |
| | (160 | ) |
-Other current assets | (16 | ) | | 1 |
| | 40 |
|
-Accounts payable | 71 |
| | 73 |
| | 3 |
|
-Accrued taxes | (84 | ) | | 93 |
| | 138 |
|
-Retail fuel cost over recovery | (76 | ) | | (162 | ) | | 191 |
|
-Other current liabilities | 2 |
| | 23 |
| | (4 | ) |
Net cash provided from operating activities | 1,837 |
| | 1,949 |
| | 2,142 |
|
Investing Activities: | | | | | |
Property additions | (1,882 | ) | | (1,272 | ) | | (1,367 | ) |
Nuclear decommissioning trust fund purchases | (237 | ) | | (352 | ) | | (439 | ) |
Nuclear decommissioning trust fund sales | 237 |
| | 351 |
| | 438 |
|
Cost of removal net of salvage | (112 | ) | | (94 | ) | | (71 | ) |
Change in construction payables | 161 |
| | (37 | ) | | (15 | ) |
Other investing activities | (43 | ) | | (34 | ) | | (34 | ) |
Net cash used for investing activities | (1,876 | ) | | (1,438 | ) | | (1,488 | ) |
Financing Activities: | | | | | |
Increase in notes payable, net | 3 |
| | — |
| | — |
|
Proceeds — | | | | | |
Senior notes | 1,100 |
| | 400 |
| | 975 |
|
Preferred stock | 250 |
| | — |
| | — |
|
Pollution control revenue bonds | — |
| | — |
| | 80 |
|
Other long-term debt | — |
| | 45 |
| | — |
|
Capital contributions from parent company | 361 |
| | 260 |
| | 22 |
|
Redemptions and repurchases — | | | | | |
Senior notes | (525 | ) | | (200 | ) | | (650 | ) |
Preferred and preference stock | (238 | ) | | — |
| | (412 | ) |
Pollution control revenue bonds | (36 | ) | | — |
| | (134 | ) |
Payment of common stock dividends | (714 | ) | | (765 | ) | | (571 | ) |
Other financing activities | (38 | ) | | (25 | ) | | (43 | ) |
Net cash provided from (used for) financing activities | 163 |
| | (285 | ) | | (733 | ) |
Net Change in Cash and Cash Equivalents | 124 |
| | 226 |
| | (79 | ) |
Cash and Cash Equivalents at Beginning of Year | 420 |
| | 194 |
| | 273 |
|
Cash and Cash Equivalents at End of Year | $ | 544 |
| | $ | 420 |
| | $ | 194 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $15, $11, and $22 capitalized, respectively) | $ | 285 |
| | $ | 277 |
| | $ | 250 |
|
Income taxes (net of refunds) | 236 |
| | (108 | ) | | 121 |
|
Noncash transactions — Accrued property additions at year-end | 245 |
| | 84 |
| | 121 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 544 |
| | $ | 420 |
|
Receivables — | | | |
Customer accounts receivable | 355 |
| | 348 |
|
Unbilled revenues | 162 |
| | 146 |
|
Affiliated | 43 |
| | 40 |
|
Other accounts and notes receivable | 55 |
| | 27 |
|
Accumulated provision for uncollectible accounts | (9 | ) | | (10 | ) |
Fossil fuel stock | 184 |
| | 205 |
|
Materials and supplies | 458 |
| | 435 |
|
Other regulatory assets, current | 124 |
| | 149 |
|
Other current assets | 90 |
| | 45 |
|
Total current assets | 2,006 |
| | 1,805 |
|
Property, Plant, and Equipment: | | | |
In service | 27,326 |
| | 26,031 |
|
Less: Accumulated provision for depreciation | 9,563 |
| | 9,112 |
|
Plant in service, net of depreciation | 17,763 |
| | 16,919 |
|
Nuclear fuel, at amortized cost | 339 |
| | 336 |
|
Construction work in progress | 908 |
| | 491 |
|
Total property, plant, and equipment | 19,010 |
| | 17,746 |
|
Other Property and Investments: | | | |
Equity investments in unconsolidated subsidiaries | 67 |
| | 66 |
|
Nuclear decommissioning trusts, at fair value | 903 |
| | 792 |
|
Miscellaneous property and investments | 124 |
| | 112 |
|
Total other property and investments | 1,094 |
| | 970 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 239 |
| | 525 |
|
Deferred under recovered regulatory clause revenues | 54 |
| | 150 |
|
Other regulatory assets, deferred | 1,272 |
| | 1,157 |
|
Other deferred charges and assets | 189 |
| | 163 |
|
Total deferred charges and other assets | 1,754 |
| | 1,995 |
|
Total Assets | $ | 23,864 |
| | $ | 22,516 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholder's Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | — |
| | $ | 561 |
|
Accounts payable — | | | |
Affiliated | 327 |
| | 297 |
|
Other | 585 |
| | 433 |
|
Customer deposits | 92 |
| | 88 |
|
Accrued taxes — | | | |
Accrued income taxes | 9 |
| | 45 |
|
Other accrued taxes | 45 |
| | 42 |
|
Accrued interest | 77 |
| | 78 |
|
Accrued compensation | 205 |
| | 193 |
|
Other regulatory liabilities, current | 1 |
| | 85 |
|
Other current liabilities | 59 |
| | 76 |
|
Total current liabilities | 1,400 |
| | 1,898 |
|
Long-Term Debt (See accompanying statements) | 7,628 |
| | 6,535 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 2,760 |
| | 4,654 |
|
Deferred credits related to income taxes | 2,082 |
| | 65 |
|
Accumulated deferred ITCs | 112 |
| | 110 |
|
Employee benefit obligations | 304 |
| | 300 |
|
Asset retirement obligations | 1,702 |
| | 1,503 |
|
Other cost of removal obligations | 609 |
| | 684 |
|
Other regulatory liabilities, deferred | 84 |
| | 100 |
|
Other deferred credits and liabilities | 63 |
| | 63 |
|
Total deferred credits and other liabilities | 7,716 |
| | 7,479 |
|
Total Liabilities | 16,744 |
| | 15,912 |
|
Redeemable Preferred Stock (See accompanying statements) | 291 |
| | 85 |
|
Preference Stock (See accompanying statements) | — |
| | 196 |
|
Common Stockholder's Equity (See accompanying statements) | 6,829 |
| | 6,323 |
|
Total Liabilities and Stockholder's Equity | $ | 23,864 |
| | $ | 22,516 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | $ | 206 |
| | $ | 206 |
| | | | |
Long-term notes payable — | | | | | | | |
5.50% to 5.55% due 2017 | — |
| | 525 |
| | | | |
5.125% due 2019 | 200 |
| | 200 |
| | | | |
3.375% due 2020 | 250 |
| | 250 |
| | | | |
2.38% to 3.95% due 2021 | 220 |
| | 220 |
| | | | |
2.45% to 5.875% due 2022 | 750 |
| | 200 |
| | | | |
2.80% to 6.125% due 2023-2047 | 4,975 |
| | 4,425 |
| | | | |
Variable rates (2.55% to 2.786% at 12/31/17) due 2021 | 25 |
| | 25 |
| | | | |
Total long-term notes payable | 6,420 |
| | 5,845 |
| | | | |
Other long-term debt — | | | | | | | |
Pollution control revenue bonds — | | | | | | | |
1.625% to 1.85% due 2034 | 207 |
| | 207 |
| | | | |
Variable rates (0.77% to 0.79% at 1/1/17) due 2017 | — |
| | 36 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | 65 |
| | 65 |
| | | | |
Variable rates (1.70% to 1.87% at 12/31/17) due 2024-2038 | 788 |
| | 788 |
| | | | |
Total other long-term debt | 1,060 |
| | 1,096 |
| | | | |
Capitalized lease obligations | 4 |
| | 4 |
| | | | |
Unamortized debt premium (discount), net | (11 | ) | | (9 | ) | | | | |
Unamortized debt issuance expense | (51 | ) | | (46 | ) | | | | |
Total long-term debt (annual interest requirement — $305 million) | 7,628 |
| | 7,096 |
| | | | |
Less amount due within one year | — |
| | 561 |
| | | | |
Long-term debt excluding amount due within one year | 7,628 |
| | 6,535 |
| | 51.7 | % | | 49.7 | % |
Redeemable Preferred Stock: | | | | | | | |
Cumulative redeemable preferred stock | | | | | | | |
$100 par or stated value — 4.20% to 4.92% | | | | | | | |
Authorized — 3,850,000 shares | | | | | | | |
Outstanding — 475,115 shares | 48 |
| | 48 |
| | | | |
$1 par value — | | | | | | | |
Authorized — 27,500,000 shares | | | | | | | |
Outstanding — 2017: 5.00% — 10,000,000 shares: $25 stated value | | | | | | | |
— 2016: 5.83% — 1,520,000 shares: $25 stated value | | | | | | | |
(annual dividend requirement — $15 million) | 243 |
| | 37 |
| | | | |
Total redeemable preferred stock | 291 |
| | 85 |
| | 2.0 |
| | 0.7 |
|
Preference Stock: | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | |
Outstanding — 2017: no shares | | | | | | | |
— 2016: 8,000,000 shares (non-cumulative): $25 stated value | — |
| | 196 |
| | — | | 1.5 |
Common Stockholder's Equity: | | | | | | | |
Common stock, par value $40 per share — | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | |
Outstanding — 30,537,500 shares | 1,222 |
| | 1,222 |
| | | | |
Paid-in capital | 2,986 |
| | 2,613 |
| | | | |
Retained earnings | 2,647 |
| | 2,518 |
| | | | |
Accumulated other comprehensive loss | (26 | ) | | (30 | ) | | | | |
Total common stockholder's equity | 6,829 |
| | 6,323 |
| | 46.3 |
| | 48.1 |
|
Total Capitalization | $ | 14,748 |
| | $ | 13,139 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
Rate NDR
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both
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Southern Company and Subsidiary Companies 2017 Annual Report
components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.
Alabama Power retired Plant Gorgas Units 6 and 7 (200 MWs) and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs) in 2015, but such units remain available on a limited basis with natural gas as the fuel source. In April 2016, Alabama Power also ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.
In accordance with this accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to regulatory assets at their respective retirement dates. These regulatory assets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement; therefore, these decisions associated with coal operations had no significant impact on Southern Company's financial statements.
Georgia Power
Rate Plans
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.
In accordance with the 2013 ARP, the Georgia PSC approved increases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) Environmental Compliance Cost Recovery tariff by approximately $75 million; (3) Demand-Side Management tariffs by approximately $3 million; and (4) Municipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2015, Georgia Power's retail ROE was within the allowed retail ROE range. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power will refund to retail customers approximately $44 million in 2018, as approved by the Georgia PSC on January 16, 2018. In 2017, Georgia Power's retail ROE was within the allowed retail ROE range, subject to review and approval by the Georgia PSC.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
On January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, Georgia Power is required to submit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on Georgia Power's cost of service and annual revenue requirements by March 6, 2018. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
In July 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in Georgia Power's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, Georgia Power filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. Georgia Power also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future Georgia Power rate case.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved Georgia Power's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved Georgia Power's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless Georgia Power deems it necessary to file a fuel case at an earlier time. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.
Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.
Georgia Power's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other regulatory liabilities, current.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in Georgia Power's regulatory asset for storm damage totaled approximately $260 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements.
At December 31, 2017 and December 31, 2016, the total balance in Georgia Power's regulatory asset related to storm damage was $333 million and $206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $303 million and $176 million included in other regulatory assets, deferred, respectively.
Gulf Power
Retail Base Rate Cases
In 2013, the Florida PSC approved a settlement agreement related to Gulf Power's 2013 retail base rate case that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction was not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, Gulf Power recognized the remaining $34.0 million reduction in depreciation.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes. Gulf Power also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to Gulf Power's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, Gulf Power must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to Gulf Power's base rates and $15.6 million to Gulf Power's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through Gulf Power's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and Gulf Power will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase Gulf Power's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
On February 7, 2018, Mississippi Power revised its annual projected Performance Evaluation Plan (PEP) filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
performance adjusted ROE of 9.33% and an increased equity ratio of 55%. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 under "Cost of Natural Gas" for additional information.
Regulatory Infrastructure Programs
Certain of Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs are designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. Initial program lengths range from nine to 10 years, with completion dates ranging from 2020 through 2025.
On February 21, 2017, the Georgia PSC approved a rate adjustment mechanism for Atlanta Gas Light that included the 2017 capital investment associated with a four-year extension of one of its existing infrastructure programs, with a total additional investment of $177 million through 2020.
Base Rate Cases
On January 31, 2018, the Illinois Commerce Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.
The Illinois Commerce Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commerce Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, Atlanta Gas Light's annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
Kemper County Energy Facility
Overview
The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper County energy facility. The mine, operated by North American Coal Corporation, started
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
commercial operation in 2013. In connection with the Kemper County energy facility construction, Mississippi Power constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement).
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper County energy facility. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. Mississippi Power has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, Mississippi Power made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) Mississippi Power to file a reserve margin plan with the Mississippi PSC by August 2018.
As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.
In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets.
Lignite Mine and CO2 Pipeline Facilities
Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. Mississippi Power expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, Mississippi Power provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses.
In addition, Mississippi Power constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO2. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, Mississippi Power reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
Nuclear Construction
Project Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, Georgia Power filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
Georgia Power expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. Georgia Power's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, Georgia Power, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of Georgia Power, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and Georgia Power and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
On November 2, 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of December 31, 2017, Georgia Power had recovered approximately $1.6 billion of financing costs. On January 30, 2018, Georgia Power filed to decrease the NCCR tariff by approximately $50 million, effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million (Customer Refunds), and the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. Georgia Power believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, which originally required the applicable unit to be placed in service before 2021. Under the Bipartisan Budget Act of 2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of Georgia Power's portion of the PTCs is approximately $500 million per unit.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In its January 11, 2018 order, the Georgia PSC also approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to June 30, 2017). The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. Georgia Power expects to file its eighteenth VCM report on February 28, 2018 requesting approval of approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred from July 1, 2017 through December 31, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.8 billion as of December 31, 2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of December 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.
4. JOINT OWNERSHIP AGREEMENTS
Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities. In August 2016, Georgia Power sold its 33% ownership interest in the Intercession City combustion turbine unit to Duke Energy Florida, LLC. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. Southern Company Gas has a 50% undivided ownership interest in the Dalton Pipeline jointly with The Williams Companies, Inc.
At December 31, 2017, Alabama Power's, Georgia Power's, Southern Power's, and Southern Company Gas' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
|
| | | | | | | | | | | | | | |
Facility (Type) | Percent Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP |
| | | (in millions) |
Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | % | | $ | 3,564 |
| | $ | 2,141 |
| | $ | 70 |
|
Plant Hatch (nuclear) | 50.1 |
| | 1,321 |
| | 595 |
| | 87 |
|
Plant Miller (coal) Units 1 and 2 | 91.8 |
| | 1,717 |
| | 619 |
| | 54 |
|
Plant Scherer (coal) Units 1 and 2 | 8.4 |
| | 261 |
| | 93 |
| | 8 |
|
Plant Wansley (coal) | 53.5 |
| | 1,053 |
| | 335 |
| | 72 |
|
Rocky Mountain (pumped storage) | 25.4 |
| | 182 |
| | 132 |
| | — |
|
Plant Stanton (combined cycle) Unit A | 65.0 |
| | 155 |
| | 55 |
| | — |
|
Dalton Pipeline (natural gas pipeline) | 50.0 |
| | 241 |
| | 2 |
| | 13 |
|
Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under "Nuclear Construction" for additional information.
Alabama Power and Georgia Power have contracted to operate and maintain their jointly-owned facilities, except for Rocky Mountain, as agents for their respective co-owners. Southern Power has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton Unit A. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing.
Southern Company Gas entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, Southern Company Gas will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
5. INCOME TAXES
Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. PowerSecure and Southern Company Gas became participants in the income tax allocation agreement as of May 9, 2016 and July 1, 2016, respectively. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Southern Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current | $ | (62 | ) | | $ | 1,184 |
| | $ | (177 | ) |
Deferred | (6 | ) | | (342 | ) | | 1,266 |
|
| (68 | ) | | 842 |
| | 1,089 |
|
State — | | | | | |
Current | 37 |
| | (108 | ) | | (33 | ) |
Deferred | 173 |
| | 217 |
| | 138 |
|
| 210 |
| | 109 |
| | 105 |
|
Total | $ | 142 |
| | $ | 951 |
| | $ | 1,194 |
|
Net cash payments (refunds) for income taxes in 2017, 2016, and 2015 were $(410) million, $(148) million, and $(9) million, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Deferred tax liabilities — | | | |
Accelerated depreciation | $ | 10,267 |
| | $ | 15,392 |
|
Property basis differences | 955 |
| | 2,708 |
|
Leveraged lease basis differences | 251 |
| | 314 |
|
Employee benefit obligations | 516 |
| | 737 |
|
Premium on reacquired debt | 54 |
| | 89 |
|
Regulatory assets associated with employee benefit obligations | 1,046 |
| | 1,584 |
|
Regulatory assets associated with AROs | 1,225 |
| | 1,781 |
|
Other | 697 |
| | 907 |
|
Total | 15,011 |
| | 23,512 |
|
Deferred tax assets — | | | |
Federal effect of state deferred taxes | 326 |
| | 597 |
|
Employee benefit obligations | 1,307 |
| | 1,868 |
|
Over recovered fuel clause | — |
| | 66 |
|
Other property basis differences | 446 |
| | 401 |
|
Deferred costs | 69 |
| | 100 |
|
ITC carryforward | 2,420 |
| | 1,974 |
|
Federal NOL carryforward | 518 |
| | 1,084 |
|
Unbilled revenue | 57 |
| | 92 |
|
Other comprehensive losses | 84 |
| | 152 |
|
AROs | 1,197 |
| | 1,732 |
|
Estimated Loss on Kemper IGCC | 722 |
| | 484 |
|
Deferred state tax assets | 328 |
| | 266 |
|
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 465 |
| | — |
|
Other | 485 |
| | 679 |
|
Total | 8,424 |
| | 9,495 |
|
Valuation allowance | (149 | ) | | (23 | ) |
Total deferred income taxes | 6,736 |
| | 14,040 |
|
Portion included in accumulated deferred tax assets | (106 | ) | | (52 | ) |
Accumulated deferred income taxes | $ | 6,842 |
| | $ | 14,092 |
|
The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased tax-related regulatory liabilities.
At December 31, 2017, the tax-related regulatory assets to be recovered from customers were $825 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.
At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $7.3 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies and the natural gas distribution utilities are amortized over the life of the related property with such amortization normally applied as a credit to
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2017, $22 million in 2016, and $21 million in 2015. Southern Power's deferred federal ITCs are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. No cash was received related to these incentives in 2017 and 2016. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. See "Unrecognized Tax Benefits" below for further information.
Tax Credit Carryforwards
At December 31, 2017, Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) which are expected to result in $2.1 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
Additionally, Southern Company had state ITC carryforwards for the state of Georgia totaling approximately $318 million, which will expire between 2020 and 2027 but are expected to be fully utilized.
Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will begin expiring in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.
At December 31, 2017, the state NOL carryforwards for Southern Company's subsidiaries were as follows:
|
| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Begins Expiring |
| (in millions) | |
Mississippi | $ | 2,890 |
| $ | 114 |
| 2032 |
Oklahoma | 986 |
| 47 |
| 2036 |
Georgia | 524 |
| 23 |
| 2019 |
New York | 229 |
| 13 |
| 2036 |
New York City | 209 |
| 15 |
| 2036 |
Florida | 304 |
| 13 |
| 2034 |
Other states | 465 |
| 24 |
| Various |
Total | $ | 5,607 |
| $ | 249 |
|
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | 12.5 |
| | 2.1 |
| | 1.9 |
|
Employee stock plans dividend deduction | (4.1 | ) | | (1.2 | ) | | (1.2 | ) |
Non-deductible book depreciation | 3.1 |
| | 0.9 |
| | 1.2 |
|
AFUDC-Equity | (2.6 | ) | | (2.0 | ) | | (2.2 | ) |
Non-deductible equity portion on Kemper IGCC write-off | 15.7 |
| | — |
| | — |
|
ITC basis difference | (1.7 | ) | | (5.0 | ) | | (1.5 | ) |
Federal PTCs | (12.1 | ) | | (1.2 | ) | | — |
|
Amortization of ITC | (4.2 | ) | | (0.9 | ) | | (0.5 | ) |
Tax Reform Legislation | (25.6 | ) | | — |
| | — |
|
Other | (2.7 | ) | | (0.4 | ) | | 0.2 |
|
Effective income tax rate | 13.3 | % | | 27.3 | % | | 32.9 | % |
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs. However, in 2017, the effective tax rate was primarily lower due to the remeasurement of deferred income taxes resulting from the Tax Reform Legislation.
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on Southern Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Unrecognized tax benefits at beginning of year | $ | 484 |
| | $ | 433 |
| | $ | 170 |
|
Tax positions increase from current periods | 10 |
| | 45 |
| | 43 |
|
Tax positions increase from prior periods | 10 |
| | 21 |
| | 240 |
|
Tax positions decrease from prior periods | (196 | ) | | (15 | ) | | (20 | ) |
Reductions due to settlements | (290 | ) | | — |
| | — |
|
Balance at end of year | $ | 18 |
| | $ | 484 |
| | $ | 433 |
|
The tax positions increase from current and prior periods for 2017 and 2016 relate primarily to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as deductions for R&E expenditures associated with the Kemper County energy facility. The tax positions decrease from prior periods for 2017 and 2016, and the reductions due to settlements for 2017, relate primarily to the
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
settlement of R&E expenditures associated with the Kemper County energy facility and federal income tax benefits from deferred ITCs. See Note 3 under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction" herein for more information.
The impact on Southern Company's effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| 2017 |
| 2016 |
| 2015 |
| (in millions) |
Tax positions impacting the effective tax rate | $ | 18 |
|
| $ | 20 |
|
| $ | 10 |
|
Tax positions not impacting the effective tax rate | — |
|
| 464 |
|
| 423 |
|
Balance of unrecognized tax benefits | $ | 18 |
|
| $ | 484 |
|
| $ | 433 |
|
The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility and Southern Company's estimate of the uncertainty related to the amount of those benefits. The tax positions not impacting the effective tax rate for 2016 and 2015 relate to deductions for R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for more information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all years presented.
Southern Company classifies interest on tax uncertainties as interest expense. Southern Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. As a result of this approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.
6. FINANCING
Securities Due Within One Year
A summary of scheduled maturities of securities due within one year at December 31 was as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Senior notes | $ | 2,354 |
| | $ | 1,995 |
|
Other long-term debt | 1,420 |
| | 485 |
|
Revenue bonds(*) | 90 |
| | 76 |
|
Capitalized leases | 31 |
| | 32 |
|
Unamortized debt issuance expense/discount | (3 | ) | | (1 | ) |
Total | $ | 3,892 |
| | $ | 2,587 |
|
| |
(*) | Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Maturities through 2022 applicable to total long-term debt are as follows: $3.9 billion in 2018; $3.2 billion in 2019; $3.2 billion in 2020; $3.1 billion in 2021; and $2.2 billion in 2022.
Bank Term Loans
Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
At December 31, 2017, Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $450 million, $45 million, $250 million, $900 million, and $420 million, respectively, of which $1.5 billion are reflected in the statements of capitalization as long-term debt and $600 million are reflected in the balance sheet as notes payable. At December 31, 2016, Southern Company, Alabama Power, Gulf Power, Mississippi Power, and Southern Power Company had outstanding bank term loans totaling $400 million, $45 million, $100 million, $1.2 billion, and $380 million, respectively, of which $2.0 billion were reflected in the statements of capitalization as long-term debt and $100 million were reflected in the balance sheet as notes payable.
In June 2017, Southern Company entered into two $100 million aggregate principal amount short-term floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR.
In August 2017, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In June 2017, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $50 million and $150 million, with maturity dates of December 1, 2017 and May 31, 2018, respectively, and one long-term floating rate bank loan of $100 million, with a maturity date of June 28, 2018, which was amended in August 2017 to extend the maturity date to October 26, 2018. These loans bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. In December 2017, Georgia Power repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
In March 2017, Gulf Power extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.
In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018.
The outstanding bank loans as of December 31, 2017 have covenants that limit debt levels to a percentage of total capitalization. The percentage is 70% for Southern Company and 65% for Alabama Power, Georgia Power, Mississippi Power, and Southern Power Company, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017, each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company was in compliance with its debt limits.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into the Loan Guarantee Agreement in 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Proceeds of advances made under the FFB Credit Facility are used to reimburse Georgia Power for Eligible Project Costs. Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion.
On September 28, 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.
All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
Upon satisfaction of all conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
At both December 31, 2017 and 2016, Georgia Power had $2.6 billion of borrowings outstanding under the FFB Credit Facility.
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
Senior Notes
Southern Company and its subsidiaries issued a total of $4.0 billion of senior notes in 2017. Southern Company issued $0.3 billion and its subsidiaries issued a total of $3.7 billion. The proceeds of Southern Company's issuances were used to repay short-term indebtedness and for other general corporate purposes. Except as described below, the proceeds of Southern Company's subsidiaries' issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs. A portion of the proceeds of Gulf Power's senior note issuances was used to redeem all of Gulf Power's outstanding shares of preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.
At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $35.1 billion and $33.0 billion, respectively, of senior notes outstanding. At December 31, 2017 and 2016, Southern Company had a total of $10.2 billion and $10.3 billion, respectively, of senior notes outstanding. These amounts include senior notes due within one year.
Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.
Junior Subordinated Notes
At December 31, 2017 and 2016, Southern Company and its subsidiaries had a total of $3.6 billion and $2.4 billion, respectively, of junior subordinated notes outstanding.
In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
In November 2017, Southern Company issued $450 million aggregate principal amount of Series 2017B 5.25% Junior Subordinated Notes due December 1, 2077. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.
In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of Georgia Power's preferred and preference stock. See "Redeemable Preferred Stock of Subsidiaries" herein for additional information.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies had $3.3 billion of outstanding pollution control revenue bond obligations at December 31, 2017 and 2016, which includes pollution control revenue bonds classified as due within one year. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
Plant Daniel Revenue Bonds
In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information.
Gas Facility Revenue Bonds
Pivotal Utility Holdings, Inc., a subsidiary of Southern Company Gas (Pivotal Utility Holdings), is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
agencies or counties to investors, and proceeds from each issuance then are loaned to Southern Company Gas. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million.
The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 12 under "Southern Company Gas – Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.
Other Revenue Bonds
Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper County energy facility and related facilities.
Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2017 and 2016. Such amounts are reflected in the statements of capitalization as other long-term debt.
First Mortgage Bonds
Nicor Gas, a subsidiary of Southern Company Gas, had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016, respectively. These bonds have been issued with maturities ranging from 2019 to 2057. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing these first mortgage bonds. See "Assets Subject to Lien" herein for additional information.
On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.
Long-Term Debt Payable to an Affiliated Trust
Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million outstanding as of December 31, 2017 and 2016, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 2017 and 2016, trust preferred securities of $200 million were outstanding.
Capital Leases
Assets acquired under capital leases are recorded in the balance sheets as property, plant, and equipment and the related obligations are classified as long-term debt.
In 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper County energy facility, which resulted in a capital lease obligation of $74 million at December 31, 2016. Following the suspension of the Kemper IGCC, Mississippi Power entered into an asset purchase and settlement agreement in December 2017 with the lessor, which terminated the capital lease obligation. See Note 3 under "Kemper County Energy Facility" for additional information.
At December 31, 2017 and 2016, the capitalized lease obligations for Georgia Power's corporate headquarters building were $22 million and $28 million, respectively, with an annual interest rate of 7.9%.
At December 31, 2017 and 2016, a subsidiary of Southern Company had capital lease obligations of approximately $177 million and $29 million, respectively, for an office building and certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.5% to 4.7%.
Assets Subject to Lien
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2017.
The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant Daniel Revenue Bonds" herein for additional information.
On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.
The first mortgage bonds issued by Nicor Gas are secured by substantially all of Nicor Gas' properties. See "First Mortgage Bonds" herein for additional information.
Under the terms of the PPA and the expansion PPA for Southern Power's Mankato project, which was acquired in 2016, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. See Note 12 under "Southern Power" for additional information.
During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock solar facility in Pecos County, Texas. Roserock is in a litigation dispute with McCarthy Building Companies, Inc. (McCarthy) regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. Southern Power intends to vigorously pursue its claims against McCarthy and defend against McCarthy's claims, the ultimate outcome of which cannot be determined at this time.
Bank Credit Arrangements
At December 31, 2017, committed credit arrangements with banks were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Executable Term Loans | | Expires Within One Year |
Company | 2018 | | 2019 | | 2020 | | 2022 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
Southern Company(a) | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Alabama Power | 35 |
| | — |
| | 500 |
| | 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
Georgia Power | — |
| | — |
| | — |
| | 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
Gulf Power | 30 |
| | 25 |
| | 225 |
| | — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 20 |
| | 10 |
|
Mississippi Power | 100 |
| | — |
| | — |
| | — |
| | 100 |
| | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Southern Power Company(b) | — |
| | — |
| | — |
| | 750 |
| | 750 |
| | 728 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c) | — |
| | — |
| | — |
| | 1,900 |
| | 1,900 |
| | 1,890 |
| | — |
| | — |
| | — |
| | — |
|
Other | 30 |
| | — |
| | — |
| | — |
| | 30 |
| | 30 |
| | 20 |
| | — |
| | 20 |
| | 10 |
|
Southern Company Consolidated | $ | 195 |
| | $ | 25 |
| | $ | 725 |
| | $ | 7,200 |
| | $ | 8,145 |
| | $ | 8,094 |
| | $ | 65 |
| | $ | — |
| | $ | 40 |
| | $ | 155 |
|
| |
(a) | Represents the Southern Company parent entity. |
| |
(b) | Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $19 million remains unused at December 31, 2017. |
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
In May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement with $1.4 billion and $500 million currently allocated to Southern Company Gas Capital and Nicor Gas, respectively, maturing in 2022. Pursuant to the new multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. In September 2017, Alabama Power also amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020. In November 2017, Gulf Power amended $195 million of its multi-year credit arrangements to extend the maturity dates from 2017 and 2018 to 2020 and Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. Compensating balances are not legally restricted from withdrawal.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Southern Company's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and most of the other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements and other hybrid securities. Additionally, for Southern Company and Southern Power Company, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power Company to the extent such debt is non-recourse to Southern Power Company and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were each in compliance with their respective debt limit covenants.
A portion of the $8.1 billion unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of December 31, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In addition, at December 31, 2017, the traditional electric operating companies had approximately $714 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to December 31, 2017, $50 million of these revenue bonds of Mississippi Power which were in a long-term interest rate mode were remarketed in an index rate mode.
Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Details of short-term borrowings were as follows:
|
| | | | | | |
| Short-term Debt at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2017: | | | |
Commercial paper | $ | 1,832 |
| | 1.8 | % |
Short-term bank debt | 607 |
| | 2.3 | % |
Total | $ | 2,439 |
| | 1.9 | % |
December 31, 2016: | | | |
Commercial paper | $ | 1,909 |
| | 1.1 | % |
Short-term bank debt | 123 |
| | 1.7 | % |
Total | $ | 2,032 |
| | 1.1 | % |
In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016, Southern Power Company subsidiaries had credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017 and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016.
Redeemable Preferred Stock of Subsidiaries
At December 31, 2016, each of the traditional electric operating companies had outstanding preferred and/or preference stock. During 2017, Alabama Power and Gulf Power each redeemed all of its outstanding preference stock and Georgia Power redeemed all of its outstanding preferred and preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power did not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "Preferred and Preference Stock of Subsidiaries," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity.
The following table presents changes during the year in redeemable preferred stock of subsidiaries for Southern Company:
|
| | | |
| Redeemable Preferred Stock of Subsidiaries |
| (in millions) |
Balance at December 31, 2014 | $ | 375 |
|
Issued | — |
|
Redeemed | (262 | ) |
Issuance costs | 5 |
|
Balance at December 31, 2015: | 118 |
|
Issued | — |
|
Redeemed | — |
|
Balance at December 31, 2016: | 118 |
|
Issued | 250 |
|
Redeemed | (38 | ) |
Issuance costs | (6 | ) |
Balance at December 31, 2017: | $ | 324 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2017, 2016, and 2015, the traditional electric operating companies and Southern Power incurred fuel expense of $4.4 billion, $4.4 billion, and $4.8 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system's future fuel needs will continue to be purchased under long-term commitments.
In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $235 million, $232 million, and $227 million for 2017, 2016, and 2015, respectively.
Estimated total obligations under these commitments at December 31, 2017 were as follows:
|
| | | | | | | |
| Operating Leases | | Other |
| (in millions) |
2018 | $ | 247 |
| | $ | 7 |
|
2019 | 250 |
| | 6 |
|
2020 | 247 |
| | 4 |
|
2021 | 249 |
| | 5 |
|
2022 | 252 |
| | 4 |
|
2023 and thereafter | 806 |
| | 38 |
|
Total | $ | 2,051 |
| | $ | 64 |
|
Pipeline Charges, Storage Capacity, and Gas Supply
Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers selling retail natural gas, as well as demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.
Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:
|
| | | |
| Pipeline Charges, Storage Capacity, and Gas Supply |
| (in millions) |
2018 | $ | 813 |
|
2019 | 552 |
|
2020 | 416 |
|
2021 | 375 |
|
2022 | 339 |
|
2023 and thereafter | 2,294 |
|
Total | $ | 4,789 |
|
Operating Leases
The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $176 million, $169 million, and $130 million for 2017, 2016, and 2015, respectively. Southern Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, estimated minimum lease payments under operating leases were as follows:
|
| | | | | | | | | | | |
| Minimum Lease Payments |
| Barges & Railcars | | Other(*) | | Total |
| (in millions) |
2018 | $ | 21 |
| | $ | 128 |
| | $ | 149 |
|
2019 | 11 |
| | 113 |
| | 124 |
|
2020 | 9 |
| | 99 |
| | 108 |
|
2021 | 8 |
| | 87 |
| | 95 |
|
2022 | 6 |
| | 77 |
| | 83 |
|
2023 and thereafter | 5 |
| | 963 |
| | 968 |
|
Total | $ | 60 |
| | $ | 1,467 |
| | $ | 1,527 |
|
| |
(*) | Includes operating leases for cellular tower space, facilities, vehicles, and other equipment. |
For the traditional electric operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions.
In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $44 million. At the termination of the leases, the lessee may renew the lease, exercise its purchase option, or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations.
Guarantees
In 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.
As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees.
8. COMMON STOCK
Stock Issued
During 2017, Southern Company issued approximately 14.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $659 million.
In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $134 million, net of $1.1 million in fees and commissions.
Shares Reserved
At December 31, 2017, a total of 71 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Omnibus Incentive Compensation Plan (which includes stock options and performance share units as discussed below), and an at-the-market program. Of the total 71 million shares reserved, there were 13 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2017.
Stock-Based Compensation
Stock-based compensation primarily in the form of performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2017, there were 5,112 current and former employees participating in the stock option, performance share unit, and restricted stock unit programs.
In conjunction with the Merger, stock-based compensation in the form of Southern Company restricted stock and performance share units was also granted to certain executives of Southern Company Gas through the Southern Company Omnibus Incentive Compensation Plan.
Performance Share Units
Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. Employees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
In determining the fair value of the TSR-based awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted:
|
| | | | | |
Year Ended December 31 | 2017 | | 2016 | | 2015 |
Expected volatility | 15.6% | | 15.0% | | 12.9% |
Expected term (in years) | 3 | | 3 | | 3 |
Interest rate | 1.4% | | 0.8% | | 1.0% |
Weighted average grant-date fair value | $49.08 | | $45.06 | | $46.38 |
The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $49.21, $48.87, and $47.75, respectively.
Total unvested performance share units outstanding as of December 31, 2016 were 3.2 million. During 2017, 1.2 million performance share units were granted and 1.5 million performance share units were vested or forfeited, resulting in 2.9 million
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
unvested performance share units outstanding at December 31, 2017. The number of shares to be issued for the three-year performance and vesting period ended December 31, 2017 will be determined in the first quarter 2018.
For the years ended December 31, 2017, 2016, and 2015, total compensation cost for performance share units recognized in income was $74 million, $96 million, and $88 million, respectively, with the related tax benefit also recognized in income of $29 million, $37 million, and $34 million, respectively. As of December 31, 2017, $30 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.25.
During 2017, 0.6 million restricted stock units were granted and 0.1 million restricted stock units were vested or forfeited, resulting in 0.7 million unvested restricted stock units outstanding at December 31, 2017, including previously issued restricted stock units related to other employee retention agreements.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $25 million with the related tax benefit also recognized in income of $10 million. As of December 31, 2017, $8 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.
Stock Options
In 2015, Southern Company discontinued the granting of stock options and all outstanding options have vested. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
Southern Company's activity in the stock option program for 2017 is summarized below:
|
| | | | | | |
| Shares Subject to Option | | Weighted Average Exercise Price |
| (in millions) | | |
Outstanding at December 31, 2016 | 24.6 |
| | $ | 41.28 |
|
Exercised | 6.0 |
| | 40.03 |
|
Cancelled | — |
| | 39.90 |
|
Outstanding and Exercisable at December 31, 2017 | 18.6 |
| | $ | 41.68 |
|
As of December 31, 2017, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately five years and the aggregate intrinsic value for the options outstanding and options exercisable was $119 million.
Total compensation cost for stock option awards and the related tax benefits recognized in income were immaterial for all years presented.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $64 million, $120 million, and $48 million, respectively. The actual tax benefit for the tax deductions from stock option exercises totaled $25 million, $46 million, and $19 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09, the excess tax benefits related to the exercise of stock options were recognized in Southern Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2017, 2016, and 2015 was $239 million, $448 million, and $154 million, respectively.
Southern Company Gas Restricted Stock Awards
At the effective time of the Merger, each outstanding award of existing Southern Company Gas performance share units was converted into an award of Southern Company's restricted stock units. Under the terms of the restricted stock awards, the employees received Southern Company stock when they satisfy the requisite service period by being continuously employed through the original three-year vesting schedule of the award being replaced. Southern Company issued 0.7 million restricted stock units with a grant-date fair value of $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration.
For the years ended December 31, 2017 and 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million, respectively, and the related tax benefit also recognized in income was $4 million for each year. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months.
Southern Company Gas Change in Control Awards
Southern Company awarded performance share units to certain Southern Company Gas employees who continued their employment with the Southern Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change in control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change in control benefit will vest and be issued one-third each year as long as the employee remains in service with Southern Company or its subsidiaries at each vest date. In addition to the change in control benefit, Southern Company common stock could be issued to the employees at the end of a performance period based on achievement of certain Southern Company common stock price metrics, as well performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares).
The change in control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change in control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance.
For the years ended December 31, 2017 and 2016, total compensation cost for the change in control awards recognized in income was $12 million and $4 million, respectively. The related tax benefit also recognized in income was $6 million for the year ended December 31, 2017 and an immaterial amount for the year ended December 31, 2016. As of December 31, 2017, approximately $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months.
Diluted Earnings Per Share
For Southern Company, the only difference in computing basic and diluted EPS is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted EPS were as follows:
|
| | | | | | | | |
| Average Common Stock Shares |
| 2017 | | 2016 | | 2015 |
| (in millions) |
As reported shares | 1,000 |
| | 951 |
| | 910 |
|
Effect of options and performance share award units | 8 |
| | 7 |
| | 4 |
|
Diluted shares | 1,008 |
| | 958 |
| | 914 |
|
Prior to the adoption of ASU 2016-09 in 2016, the effect of options and performance share award units included the assumed impacts of any excess tax benefits from the exercise of all "in the money" outstanding share based awards. Stock options and
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
performance share award units that were not included in the diluted EPS calculation because they were anti-dilutive were immaterial in all years presented.
Common Stock Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2017, consolidated retained earnings included $5.3 billion of undistributed retained earnings of the subsidiaries.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2017 under the NEIL policies would be $55 million and $81 million, respectively.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 331 |
| | $ | 239 |
| | $ | — |
| | $ | — |
| | $ | 570 |
|
Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Foreign currency derivatives | — |
| | 129 |
| | — |
| | — |
| | 129 |
|
Nuclear decommissioning trusts:(c) | | | | | | | | | |
Domestic equity | 690 |
| | 82 |
| | — |
| | — |
| | 772 |
|
Foreign equity | 62 |
| | 224 |
| | — |
| | — |
| | 286 |
|
U.S. Treasury and government agency securities | — |
| | 251 |
| | — |
| | — |
| | 251 |
|
Municipal bonds | — |
| | 68 |
| | — |
| | — |
| | 68 |
|
Corporate bonds | 21 |
| | 315 |
| | — |
| | — |
| | 336 |
|
Mortgage and asset backed securities | — |
| | 57 |
| | — |
| | — |
| | 57 |
|
Private equity | — |
| | — |
| | — |
| | 29 |
| | 29 |
|
Other | 19 |
| | 12 |
| | — |
| | — |
| | 31 |
|
Cash equivalents | 1,455 |
| | — |
| | — |
| | — |
| | 1,455 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 2,587 |
| | $ | 1,378 |
| | $ | 1 |
| | $ | 29 |
| | $ | 3,995 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 480 |
| | $ | 253 |
| | $ | — |
| | $ | — |
| | $ | 733 |
|
Interest rate derivatives | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Contingent consideration | — |
| | — |
| | 22 |
| | — |
| | 22 |
|
Total | $ | 480 |
| | $ | 314 |
| | $ | 22 |
| | $ | — |
| | $ | 816 |
|
| |
(a) | Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $193 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
As of December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 338 |
| | $ | 333 |
| | $ | — |
| | $ | — |
| | $ | 671 |
|
Interest rate derivatives | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Nuclear decommissioning trusts:(c) | | | | | | | | | |
Domestic equity | 589 |
| | 73 |
| | — |
| | — |
| | 662 |
|
Foreign equity | 48 |
| | 168 |
| | — |
| | — |
| | 216 |
|
U.S. Treasury and government agency securities | — |
| | 92 |
| | — |
| | — |
| | 92 |
|
Municipal bonds | — |
| | 73 |
| | — |
| | — |
| | 73 |
|
Corporate bonds | 22 |
| | 310 |
| | — |
| | — |
| | 332 |
|
Mortgage and asset backed securities | — |
| | 183 |
| | — |
| | — |
| | 183 |
|
Private equity | — |
| | — |
| | — |
| | 20 |
| | 20 |
|
Other | 11 |
| | 15 |
| | — |
| | — |
| | 26 |
|
Cash equivalents | 1,172 |
| | — |
| | — |
| | — |
| | 1,172 |
|
Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
Total | $ | 2,189 |
| | $ | 1,261 |
| | $ | 1 |
| | $ | 20 |
| | $ | 3,471 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 345 |
| | $ | 285 |
| | $ | — |
| | $ | — |
| | $ | 630 |
|
Interest rate derivatives | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Foreign currency derivatives | — |
| | 58 |
| | — |
| | — |
| | 58 |
|
Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
Total | $ | 345 |
| | $ | 372 |
| | $ | 18 |
| | $ | — |
| | $ | 735 |
|
| |
(a) | Energy-related derivatives exclude $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives exclude cash collateral of $62 million. |
| |
(c) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending program. See Note 1 under "Nuclear Decommissioning" for additional information. |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of December 31, 2017 and 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) |
|
|
|
|
As of December 31, 2017 | $ | 29 |
|
| $ | 21 |
|
| Not Applicable |
| Not Applicable |
As of December 31, 2016 | $ | 20 |
| | $ | 25 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.
As of December 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 48,151 |
| | $ | 51,348 |
|
2016 | $ | 45,080 |
| | $ | 46,286 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
11. DERIVATIVES
The Southern Company system is exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information.
Energy-Related Derivatives
Southern Company and certain subsidiaries enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, adversely affect results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 621 million mmBtu for the Southern Company system, with the longest hedge date of 2021 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2026 for derivatives not designated as hedges.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 32 million mmBtu.
The estimated pre-tax gains (losses) related to energy-related derivatives that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 total $(11) million for Southern Company.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At December 31, 2017, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount |
| Interest Rate Received |
| Weighted Average Interest Rate Paid |
| Hedge Maturity Date |
| Fair Value Gain (Loss) December 31, 2017 |
| (in millions) |
|
|
|
|
|
|
| (in millions) |
Cash Flow Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| $ | 900 |
|
| 1-month LIBOR |
| 0.79% |
| March 2018 |
| $ | 1 |
|
Fair Value Hedges of Existing Debt |
|
|
|
|
|
|
|
|
| 250 |
| | 5.40% | | 3-month LIBOR + 4.02% | | June 2018 | | — |
|
| 500 |
| | 1.95% | | 3-month LIBOR + 0.76% | | December 2018 | | (3 | ) |
| 200 |
| | 4.25% | | 3-month LIBOR + 2.46% | | December 2019 | | (1 | ) |
| 300 |
| | 2.75% | | 3-month LIBOR + 0.92% | | June 2020 | | (2 | ) |
| 1,500 |
| | 2.35% | | 1-month LIBOR + 0.87% | | July 2021 | | (31 | ) |
Total | $ | 3,650 |
|
|
|
|
|
|
|
| $ | (36 | ) |
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2018 total $(20) million. Deferred gains and losses are expected to be amortized into earnings through 2046.
Foreign Currency Derivatives
Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017, the following foreign currency derivatives were outstanding: |
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
| $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 55 |
|
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 51 |
|
Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 106 |
|
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2018 total $(23) million.
Derivative Financial Statement Presentation and Amounts
Southern Company and its subsidiaries enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | |
| 2017 | | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 10 |
| $ | 43 |
| | $ | 73 |
| $ | 27 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 7 |
| 24 |
| | 25 |
| 33 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 17 |
| $ | 67 |
| | $ | 98 |
| $ | 60 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 14 |
| | $ | 23 |
| $ | 7 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | 1 |
| 4 |
| | 12 |
| 1 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 34 |
| | 1 |
| 28 |
|
Foreign currency derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| 23 |
| | — |
| 25 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 129 |
| — |
| | — |
| 33 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 133 |
| $ | 75 |
| | $ | 36 |
| $ | 94 |
|
Derivatives not designated as hedging instruments | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 380 |
| $ | 437 |
| | $ | 489 |
| $ | 483 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 170 |
| 215 |
| | 66 |
| 81 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| — |
| | 1 |
| — |
|
Total derivatives not designated as hedging instruments | $ | 550 |
| $ | 652 |
| | $ | 556 |
| $ | 564 |
|
Gross amounts recognized | $ | 700 |
| $ | 794 |
| | $ | 690 |
| $ | 718 |
|
Gross amounts offset(a) | $ | (405 | ) | $ | (598 | ) | | $ | (462 | ) | $ | (524 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 295 |
| $ | 196 |
| | $ | 228 |
| $ | 194 |
|
| |
(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively. |
| |
(b) | Net amounts of derivative instruments outstanding exclude premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | | | | |
| Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (34 | ) | | $ | (16 | ) | | Other regulatory liabilities, current | $ | 7 |
| | $ | 56 |
|
| Other regulatory assets, deferred | (18 | ) | | (19 | ) | | Other regulatory liabilities, deferred | 1 |
| | 12 |
|
Total energy-related derivative gains (losses)(*) | | $ | (52 | ) | | $ | (35 | ) | | | $ | 8 |
| | $ | 68 |
|
| |
(*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million and $8 million as of December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |
| Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Amount |
| | Amount |
Derivative Category | 2017 |
| 2016 |
| 2015 |
| Statements of Income Location | 2017 |
| 2016 |
| 2015 |
| (in millions) |
| | (in millions) |
Energy-related derivatives | $ | (47 | ) |
| $ | 18 |
|
| $ | — |
|
| Depreciation and amortization | $ | (16 | ) |
| $ | 2 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
| Cost of natural gas | (2 | ) |
| (1 | ) |
| — |
|
Interest rate derivatives | (2 | ) |
| (180 | ) |
| (22 | ) |
| Interest expense, net of amounts capitalized | (21 | ) |
| (18 | ) |
| (9 | ) |
Foreign currency derivatives | 140 |
|
| (58 | ) |
| — |
|
| Interest expense, net of amounts capitalized | (23 | ) |
| (13 | ) |
| — |
|
|
|
|
|
|
|
|
|
|
| Other income (expense), net(*) | 160 |
|
| (82 | ) |
| — |
|
Total | $ | 91 |
|
| $ | (220 | ) |
| $ | (22 | ) |
|
| $ | 98 |
|
| $ | (112 | ) |
| $ | (9 | ) |
| |
(*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record euro-denominated notes. |
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | | | | | |
Derivatives in Fair Value Hedging Relationships |
| Gain (Loss) |
Derivative Category | Statements of Income Location | 2017 | | 2016 | | 2015 |
| | (in millions) |
Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (22 | ) | | $ | (21 | ) | | $ | 2 |
|
For all years presented, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: |
| | | | | | | | | | | | |
Derivatives Not Designated as Hedging Instruments |
| Unrealized Gain (Loss) Recognized in Income |
|
| Amount |
Derivative Category | Statements of Income Location | 2017 |
| 2016 |
| 2015 |
|
| (in millions) |
Energy-related derivatives | Wholesale electric revenues | $ | (4 | ) |
| $ | 2 |
|
| $ | (5 | ) |
| Fuel | — |
|
| — |
|
| 3 |
|
| Natural gas revenues(*) | (80 | ) |
| 33 |
|
| — |
|
| Cost of natural gas | (2 | ) |
| 3 |
|
| — |
|
Total |
| $ | (86 | ) |
| $ | 38 |
|
| $ | (2 | ) |
| |
(*) | Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $23 million and $6 million for the years ended December 31, 2017 and 2016, respectively. |
For the years ended December 31, 2017, 2016, and 2015, the pre-tax effects of interest rate derivatives not designated as hedging instruments were immaterial.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.
At December 31, 2017, the fair value of energy-related and interest rate derivative liabilities with contingent features was $15 million and $7 million, respectively. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $14 million and $7 million for energy-related and interest rate derivative contracts, respectively.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Southern Company system maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company may be required to deposit cash into these accounts. At December 31, 2017, cash collateral held on deposit in broker margin accounts was $193 million.
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's exposure to counterparty credit risk. Southern Company may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
Southern Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
12. ACQUISITIONS AND DISPOSITIONS
Southern Company
Merger with Southern Company Gas
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
Southern Company Gas Purchase Price | |
| (in millions) |
Current assets | $ | 1,557 |
|
Property, plant, and equipment | 10,108 |
|
Goodwill | 5,967 |
|
Intangible assets | 400 |
|
Regulatory assets | 1,118 |
|
Other assets | 229 |
|
Current liabilities | (2,201 | ) |
Other liabilities | (4,742 | ) |
Long-term debt | (4,261 | ) |
Noncontrolling interest | (174 | ) |
Total purchase price | $ | 8,001 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $3.9 billion and $1.7 billion and net income of $243 million and $114 million for 2017 and 2016, respectively.
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.
|
| | | | | | |
| 2016 | 2015 |
| | |
Operating revenues (in millions) | $ | 21,791 |
| $ | 21,430 |
|
Net income attributable to Southern Company (in millions) | $ | 2,591 |
| $ | 2,665 |
|
Basic EPS | $ | 2.70 |
| $ | 2.85 |
|
Diluted EPS | $ | 2.68 |
| $ | 2.84 |
|
These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.
Acquisition of PowerSecure
In May 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.
The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:
|
| | | |
PowerSecure Purchase Price | |
| (in millions) |
Current assets | $ | 172 |
|
Property, plant, and equipment | 46 |
|
Intangible assets | 106 |
|
Goodwill | 284 |
|
Other assets | 4 |
|
Current liabilities | (121 | ) |
Long-term debt, including current portion | (48 | ) |
Deferred credits and other liabilities | (14 | ) |
Total purchase price | $ | 429 |
|
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).
The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.
Southern Power
During 2017 and 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, Southern Power acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, Southern Power and the class B member are
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.
The following table presents Southern Power's acquisition activity for the year ended, and subsequent to, December 31, 2017.
|
| | | | | | | | | |
Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual/Expected COD | PPA Contract Period |
Business Acquisitions During the Year Ended December 31, 2017 |
Bethel | Wind | Invenergy Wind Global LLC, January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
Cactus Flats(a) | Wind | RES America Developments, Inc. July 31, 2017 | 148 | Concho County, TX | 100 | % | | Third quarter 2018 | 12 years and 15 years |
Business Acquisitions Subsequent to December 31, 2017 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC, January 26, 2018 | 20 | Kern County, CA | 100% of Class B |
| (b) | March 2018 | 20 years |
| |
(a) | On July 31, 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, Southern Power expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. |
| |
(b) | Southern Power owns 100% of the class B membership interest under a tax equity partnership agreement. |
Business Acquisitions During the Year Ended December 31, 2017
Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million. The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows:
|
| | | |
| 2017 |
| (in millions) |
Restricted cash | $ | 16 |
|
CWIP | 534 |
|
Other assets | 5 |
|
Accounts payable | (16 | ) |
Total purchase price | $ | 539 |
|
In 2017, total revenues of $15 million and net income of $17 million, primarily as a result of PTCs, was recognized by Southern Power related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Construction Projects in Progress
During the year ended December 31, 2017, in accordance with its overall growth strategy, Southern Power continued construction on the 345-MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, construction costs included in CWIP related to these projects totaled $188 million. The ultimate outcome of these matters cannot be determined at this time.
Development Projects
During 2017, as part of Southern Power's renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
The following table presents Southern Power's acquisitions for the year ended December 31, 2016.
|
| | | | | | | | | | |
Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual COD | PPA Contract Period |
Acquisitions for the Year Ended December 31, 2016 |
Boulder 1 | Solar | SunPower November 16, 2016 | 100 | | Clark County, NV | 51 | % | (a) | December 2016 | 20 years |
Calipatria | Solar | Solar Frontier Americas Holding LLC February 11, 2016 | 20 | | Imperial County, CA | 100 | % | (b) | February 2016 | 20 years |
East Pecos | Solar | First Solar, Inc. March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | March 2017 | 15 years |
Grant Plains | Wind | Apex Clean Energy Holdings, LLC August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | 20 years and 12 years (c) |
Grant Wind | Wind | Apex Clean Energy Holdings, LLC April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | 20 years |
Henrietta | Solar | SunPower July 1, 2016 | 102 | | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
Lamesa | Solar | RES America Developments Inc. July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | April 2017 | 15 years |
Mankato (d) | Natural Gas | Calpine Corporation October 26, 2016 | 375 | | Mankato, MN | 100 | % | | N/A (e) | 10 years |
Passadumkeag | Wind | Quantum Utility Generation, LLC June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
Rutherford | Solar | Cypress Creek Renewables, LLC July 1, 2016 | 74 | | Rutherford County, NC | 100 | % | (b) | December 2016 | 15 years |
Salt Fork | Wind | EDF Renewable Energy, Inc. December 1, 2016 | 174 | | Donley and Gray Counties, TX | 100 | % | | December 2016 | 14 years and 12 years |
Tyler Bluff | Wind | EDF Renewable Energy, Inc. December 21, 2016 | 125 | | Cooke County, TX | 100 | % | | December 2016 | 12 years |
Wake Wind | Wind | Invenergy October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | (f) | October 2016 | 12 years |
| |
(a) | Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
(b) | Southern Power originally purchased 90%, with a minority owner owning 10%. During 2017, Southern Power acquired the remaining 10% ownership interest. |
| |
(c) | In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
(d) | Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. |
| |
(e) | The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility. |
| |
(f) | Southern Power owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Acquisitions During the Year Ended December 31, 2016
Southern Power's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to Southern Power was approximately $2.6 billion for these acquisitions. In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows:
|
| | | |
| 2016 |
| (in millions) |
CWIP | $ | 2,354 |
|
Property, plant, and equipment | 302 |
|
Intangible assets (a) | 128 |
|
Other assets | 52 |
|
Accounts payable | (16 | ) |
Debt | (217 | ) |
Total purchase price | $ | 2,603 |
|
| |
Funded by: | |
Southern Power (b) (c) | $ | 2,345 |
|
Noncontrolling interests (d) (e) | 258 |
|
Total purchase price | $ | 2,603 |
|
| |
(a) | Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. |
| |
(b) | At December 31, 2016, $461 million is included in acquisitions payable on the balance sheets. |
| |
(c) | Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. |
| |
(d) | Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the statements of stockholders' equity. |
| |
(e) | Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. |
Southern Company Gas
Investment in Southern Natural Gas
In September 2016, Southern Company Gas completed its acquisition from Kinder Morgan, Inc. of a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of the acquisition was approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
Acquisition of Remaining Interest in SouthStar
SouthStar Energy Services, LLC (SouthStar) is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. Southern Company Gas previously had an 85% ownership interest in SouthStar, with Piedmont Natural Gas Company, Inc.'s (Piedmont) owning the remaining 15%. In October 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million.
Proposed Sale of Elizabethtown Gas and Elkton Gas
On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. Southern Company Gas and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
13. SEGMENT AND RELATED INFORMATION
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $392 million, $419 million, and $417 million in 2017, 2016, and 2015, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were $23 million and $119 million, respectively, in 2017 and $11 million and $17 million, respectively, in 2016. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2017, 2016, and 2015 was as follows:
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| (in millions) |
2017 | | | | | | | | |
Operating revenues | $ | 16,884 |
| $ | 2,075 |
| $ | (419 | ) | $ | 18,540 |
| $ | 3,920 |
| $ | 741 |
| $ | (170 | ) | $ | 23,031 |
|
Depreciation and amortization | 1,954 |
| 503 |
| — |
| 2,457 |
| 501 |
| 52 |
| — |
| 3,010 |
|
Interest income | 14 |
| 7 |
| — |
| 21 |
| 3 |
| 11 |
| (9 | ) | 26 |
|
Earnings from equity method investments | 1 |
| — |
| — |
| 1 |
| 106 |
| (1 | ) | — |
| 106 |
|
Interest expense | 820 |
| 191 |
| — |
| 1,011 |
| 200 |
| 490 |
| (7 | ) | 1,694 |
|
Income taxes | 1,021 |
| (939 | ) | — |
| 82 |
| 367 |
| (307 | ) | — |
| 142 |
|
Segment net income (loss)(a)(b)(c) | (193 | ) | 1,071 |
| — |
| 878 |
| 243 |
| (279 | ) | — |
| 842 |
|
Total assets | 72,204 |
| 15,206 |
| (325 | ) | 87,085 |
| 22,987 |
| 2,552 |
| (1,619 | ) | 111,005 |
|
Gross property additions | 3,836 |
| 268 |
| — |
| 4,104 |
| 1,525 |
| 355 |
| — |
| 5,984 |
|
2016 | | | | | | | | |
Operating revenues | $ | 16,803 |
| $ | 1,577 |
| $ | (439 | ) | $ | 17,941 |
| $ | 1,652 |
| $ | 463 |
| $ | (160 | ) | $ | 19,896 |
|
Depreciation and amortization | 1,881 |
| 352 |
| — |
| 2,233 |
| 238 |
| 31 |
| — |
| 2,502 |
|
Interest income | 6 |
| 7 |
| — |
| 13 |
| 2 |
| 20 |
| (15 | ) | 20 |
|
Earnings from equity method investments | 2 |
| — |
| — |
| 2 |
| 60 |
| (3 | ) | — |
| 59 |
|
Interest expense | 814 |
| 117 |
| — |
| 931 |
| 81 |
| 317 |
| (12 | ) | 1,317 |
|
Income taxes | 1,286 |
| (195 | ) | — |
| 1,091 |
| 76 |
| (216 | ) | — |
| 951 |
|
Segment net income (loss)(a) (b) | 2,233 |
| 338 |
| — |
| 2,571 |
| 114 |
| (230 | ) | (7 | ) | 2,448 |
|
Total assets | 72,141 |
| 15,169 |
| (316 | ) | 86,994 |
| 21,853 |
| 2,474 |
| (1,624 | ) | 109,697 |
|
Gross property additions | 4,852 |
| 2,114 |
| — |
| 6,966 |
| 618 |
| 41 |
| (1 | ) | 7,624 |
|
2015 | | | | | | | | |
Operating revenues | $ | 16,491 |
| $ | 1,390 |
| $ | (439 | ) | $ | 17,442 |
| $ | — |
| $ | 152 |
| $ | (105 | ) | $ | 17,489 |
|
Depreciation and amortization | 1,772 |
| 248 |
| — |
| 2,020 |
| — |
| 14 |
| — |
| 2,034 |
|
Interest income | 19 |
| 2 |
| 1 |
| 22 |
| — |
| 6 |
| (5 | ) | 23 |
|
Earnings from equity method investments | 1 |
| — |
| — |
| 1 |
| — |
| (1 | ) | — |
| — |
|
Interest expense | 697 |
| 77 |
| — |
| 774 |
| — |
| 69 |
| (3 | ) | 840 |
|
Income taxes | 1,305 |
| 21 |
| — |
| 1,326 |
| — |
| (132 | ) | — |
| 1,194 |
|
Segment net income (loss)(a) (b) | 2,186 |
| 215 |
| — |
| 2,401 |
| — |
| (32 | ) | (2 | ) | 2,367 |
|
Total assets | 69,052 |
| 8,905 |
| (397 | ) | 77,560 |
| — |
| 1,819 |
| (1,061 | ) | 78,318 |
|
Gross property additions | 5,124 |
| 1,005 |
| — |
| 6,129 |
| — |
| 40 |
| — |
| 6,169 |
|
| |
(a) | Attributable to Southern Company. |
| |
(b) | Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.4 billion ($2.4 billion after tax) in 2017, $428 million ($264 million after tax) in 2016, and $365 million ($226 million after tax) in 2015. See Note 3 under "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information. |
| |
(c) | Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) in 2017. See Note 3 under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
Products and Services
|
| | | | | | | | | | | | | | | |
Electric Utilities' Revenues |
Year | Retail | | Wholesale | | Other | | Total |
| (in millions) |
2017 | $ | 15,330 |
| | $ | 2,426 |
| | $ | 784 |
| | $ | 18,540 |
|
2016 | 15,234 |
| | 1,926 |
| | 781 |
| | 17,941 |
|
2015 | 14,987 |
| | 1,798 |
| | 657 |
| | 17,442 |
|
|
| | | | | | | | | | | | | | | |
Southern Company Gas' Revenues |
Year | Gas Distribution Operations | | Gas Marketing Services | | All Other | | Total |
| (in millions) |
2017 | $ | 3,024 |
| | $ | 860 |
| | $ | 36 |
| | $ | 3,920 |
|
2016 | 1,266 |
| | 354 |
| | 32 |
| | 1,652 |
|
NOTES (continued)
Southern Company and Subsidiary Companies 2017 Annual Report
14. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 2017 and 2016 is as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Consolidated Net Income Attributable to Southern Company | | Per Common Share |
| Operating Revenues | | Operating Income | | | Basic Earnings | | Diluted Earnings | | | | Trading Price Range |
Quarter Ended | | Dividends | | High | | Low |
| (in millions) | | | | | | | | | | |
March 2017 | $ | 5,771 |
| | $ | 1,306 |
| | $ | 658 |
| | $ | 0.66 |
| | $ | 0.66 |
| | $ | 0.5600 |
| | $ | 51.47 |
| | $ | 47.57 |
|
June 2017 | 5,430 |
| | (1,594 | ) | | (1,381 | ) | | (1.38 | ) | | (1.37 | ) | | 0.5800 |
| | 51.97 |
| | 47.87 |
|
September 2017 | 6,201 |
| | 2,045 |
| | 1,069 |
| | 1.07 |
| | 1.06 |
| | 0.5800 |
| | 50.80 |
| | 46.71 |
|
December 2017 | 5,629 |
| | 794 |
| | 496 |
| | 0.49 |
| | 0.49 |
| | 0.5800 |
| | 53.51 |
| | 47.92 |
|
| | | | | | | | | | | | | | | |
March 2016 | $ | 3,992 |
| | $ | 940 |
| | $ | 489 |
| | $ | 0.53 |
| | $ | 0.53 |
| | $ | 0.5425 |
| | $ | 51.73 |
| | $ | 46.00 |
|
June 2016 | 4,459 |
| | 1,185 |
| | 623 |
| | 0.67 |
| | 0.66 |
| | 0.5600 |
| | 53.64 |
| | 47.62 |
|
September 2016 | 6,264 |
| | 1,917 |
| | 1,139 |
| | 1.18 |
| | 1.17 |
| | 0.5600 |
| | 54.64 |
| | 50.00 |
|
December 2016 | 5,181 |
| | 587 |
| | 197 |
| | 0.20 |
| | 0.20 |
| | 0.5600 |
| | 52.23 |
| | 46.20 |
|
As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $208 million ($185 million after tax) in the fourth quarter 2017, $34 million ($21 million after tax) in the third quarter 2017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $108 million ($67 million after tax) in the first quarter 2017, $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, and $53 million ($33 million after tax) in the first quarter 2016. See Note 3 under "Kemper County Energy Facility" for additional information.
As a result of the Tax Reform Legislation, the Southern Company system recorded a total income tax benefit of $264 million in the fourth quarter 2017. See Note 5 for additional information.
The Southern Company system's business is influenced by seasonal weather conditions.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Total Assets (in millions)(b)(c) | $ | 111,005 |
| | $ | 109,697 |
| | $ | 78,318 |
| | $ | 70,233 |
| | $ | 64,264 |
|
Gross Property Additions (in millions) | $ | 5,984 |
| | $ | 7,624 |
| | $ | 6,169 |
| | $ | 6,522 |
| | $ | 5,868 |
|
Return on Average Common Equity (percent)(d) | 3.44 |
| | 10.80 |
| | 11.68 |
| | 10.08 |
| | 8.82 |
|
Cash Dividends Paid Per Share of Common Stock | $ | 2.3000 |
| | $ | 2.2225 |
| | $ | 2.1525 |
| | $ | 2.0825 |
| | $ | 2.0125 |
|
Consolidated Net Income Attributable to Southern Company (in millions)(d) | $ | 842 |
| | $ | 2,448 |
| | $ | 2,367 |
| | $ | 1,963 |
| | $ | 1,644 |
|
Earnings Per Share — | | | | | | | | | |
Basic | $ | 0.84 |
| | $ | 2.57 |
| | $ | 2.60 |
| | $ | 2.19 |
| | $ | 1.88 |
|
Diluted | 0.84 |
| | 2.55 |
| | 2.59 |
| | 2.18 |
| | 1.87 |
|
Capitalization (in millions): | | | | | | | | | |
Common stock equity | $ | 24,167 |
| | $ | 24,758 |
| | $ | 20,592 |
| | $ | 19,949 |
| | $ | 19,008 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 1,361 |
| | 1,854 |
| | 1,390 |
| | 977 |
| | 756 |
|
Redeemable preferred stock of subsidiaries | 324 |
| | 118 |
| | 118 |
| | 375 |
| | 375 |
|
Redeemable noncontrolling interests | — |
| | 164 |
| | 43 |
| | 39 |
| | — |
|
Long-term debt(b) | 44,462 |
| | 42,629 |
| | 24,688 |
| | 20,644 |
| | 21,205 |
|
Total (excluding amounts due within one year) | $ | 70,314 |
| | $ | 69,523 |
| | $ | 46,831 |
| | $ | 41,984 |
| | $ | 41,344 |
|
Capitalization Ratios (percent): | | | | | | | | | |
Common stock equity | 34.4 |
| | 35.6 |
| | 44.0 |
| | 47.5 |
| | 46.0 |
|
Preferred and preference stock of subsidiaries and noncontrolling interests | 1.9 |
| | 2.7 |
| | 3.0 |
| | 2.3 |
| | 1.8 |
|
Redeemable preferred stock of subsidiaries | 0.5 |
| | 0.2 |
| | 0.3 |
| | 0.9 |
| | 0.9 |
|
Redeemable noncontrolling interests | — |
| | 0.2 |
| | 0.1 |
| | 0.1 |
| | — |
|
Long-term debt(b) | 63.2 |
| | 61.3 |
| | 52.6 |
| | 49.2 |
| | 51.3 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Other Common Stock Data: | | | | | | | | | |
Book value per share | $ | 23.99 |
| | $ | 25.00 |
| | $ | 22.59 |
| | $ | 21.98 |
| | $ | 21.43 |
|
Market price per share: | | | | | | | | | |
High | $ | 53.51 |
| | $ | 54.64 |
| | $ | 53.16 |
| | $ | 51.28 |
| | $ | 48.74 |
|
Low | 46.71 |
| | 46.00 |
| | 41.40 |
| | 40.27 |
| | 40.03 |
|
Close (year-end) | 48.09 |
| | 49.19 |
| | 46.79 |
| | 49.11 |
| | 41.11 |
|
Market-to-book ratio (year-end) (percent) | 200.5 |
| | 196.8 |
| | 207.2 |
| | 223.4 |
| | 191.8 |
|
Price-earnings ratio (year-end) (times) | 57.3 |
| | 19.1 |
| | 18.0 |
| | 22.4 |
| | 21.9 |
|
Dividends paid (in millions) | $ | 2,300 |
| | $ | 2,104 |
| | $ | 1,959 |
| | $ | 1,866 |
| | $ | 1,762 |
|
Dividend yield (year-end) (percent) | 4.8 |
| | 4.5 |
| | 4.6 |
| | 4.2 |
| | 4.9 |
|
Dividend payout ratio (percent) | 273.2 |
| | 86.0 |
| | 82.7 |
| | 95.0 |
| | 107.1 |
|
Shares outstanding (in thousands): | | | | | | | | | |
Average | 1,000,336 |
| | 951,332 |
| | 910,024 |
| | 897,194 |
| | 876,755 |
|
Year-end | 1,007,603 |
| | 990,394 |
| | 911,721 |
| | 907,777 |
| | 887,086 |
|
Stockholders of record (year-end) | 120,803 |
| | 126,338 |
| | 131,771 |
| | 137,369 |
| | 143,800 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million and $139 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. |
(c) | A reclassification of deferred tax assets from Total Assets of $488 million and $143 million is reflected for years 2014 and 2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. |
(d) | A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 6,515 |
| | $ | 6,614 |
| | $ | 6,383 |
| | $ | 6,499 |
| | $ | 6,011 |
|
Commercial | 5,439 |
| | 5,394 |
| | 5,317 |
| | 5,469 |
| | 5,214 |
|
Industrial | 3,262 |
| | 3,171 |
| | 3,172 |
| | 3,449 |
| | 3,188 |
|
Other | 114 |
| | 55 |
| | 115 |
| | 133 |
| | 128 |
|
Total retail | 15,330 |
| | 15,234 |
| | 14,987 |
| | 15,550 |
| | 14,541 |
|
Wholesale | 2,426 |
| | 1,926 |
| | 1,798 |
| | 2,184 |
| | 1,855 |
|
Total revenues from sales of electricity | 17,756 |
| | 17,160 |
| | 16,785 |
| | 17,734 |
| | 16,396 |
|
Natural gas revenues | 3,791 |
| | 1,596 |
| | — |
| | — |
| | — |
|
Other revenues | 1,484 |
| | 1,140 |
| | 704 |
| | 733 |
| | 691 |
|
Total | $ | 23,031 |
| | $ | 19,896 |
| | $ | 17,489 |
| | $ | 18,467 |
| | $ | 17,087 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 50,536 |
| | 53,337 |
| | 52,121 |
| | 53,347 |
| | 50,575 |
|
Commercial | 52,340 |
| | 53,733 |
| | 53,525 |
| | 53,243 |
| | 52,551 |
|
Industrial | 52,785 |
| | 52,792 |
| | 53,941 |
| | 54,140 |
| | 52,429 |
|
Other | 846 |
| | 883 |
| | 897 |
| | 909 |
| | 902 |
|
Total retail | 156,507 |
| | 160,745 |
| | 160,484 |
| | 161,639 |
| | 156,457 |
|
Wholesale sales | 49,034 |
| | 37,043 |
| | 30,505 |
| | 32,786 |
| | 26,944 |
|
Total | 205,541 |
| | 197,788 |
| | 190,989 |
| | 194,425 |
| | 183,401 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.89 |
| | 12.40 |
| | 12.25 |
| | 12.18 |
| | 11.89 |
|
Commercial | 10.39 |
| | 10.04 |
| | 9.93 |
| | 10.27 |
| | 9.92 |
|
Industrial | 6.18 |
| | 6.01 |
| | 5.88 |
| | 6.37 |
| | 6.08 |
|
Total retail | 9.80 |
| | 9.48 |
| | 9.34 |
| | 9.62 |
| | 9.29 |
|
Wholesale | 4.95 |
| | 5.20 |
| | 5.89 |
| | 6.66 |
| | 6.88 |
|
Total sales | 8.64 |
| | 8.68 |
| | 8.79 |
| | 9.12 |
| | 8.94 |
|
Average Annual Kilowatt-Hour | | | | | | | | | |
Use Per Residential Customer | 11,618 |
| | 12,387 |
| | 13,318 |
| | 13,765 |
| | 13,144 |
|
Average Annual Revenue | | | | | | | | | |
Per Residential Customer | $ | 1,498 |
| | $ | 1,541 |
| | $ | 1,630 |
| | $ | 1,679 |
| | $ | 1,562 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 46,936 |
| | 46,291 |
| | 44,223 |
| | 46,549 |
| | 45,502 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 31,956 |
| | 32,272 |
| | 36,794 |
| | 37,234 |
| | 27,555 |
|
Summer | 34,874 |
| | 35,781 |
| | 36,195 |
| | 35,396 |
| | 33,557 |
|
System Reserve Margin (at peak) (percent)(b) | 30.8 |
| | 34.2 |
| | 33.2 |
| | 19.8 |
| | 21.5 |
|
Annual Load Factor (percent) | 61.4 |
| | 61.5 |
| | 59.9 |
| | 59.6 |
| | 63.2 |
|
Plant Availability (percent): | | | | | | | | | |
Fossil-steam | 84.5 |
| | 86.4 |
| | 86.1 |
| | 85.8 |
| | 87.7 |
|
Nuclear | 94.7 |
| | 93.3 |
| | 93.5 |
| | 91.5 |
| | 91.5 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | Beginning in 2014, system reserve margin is calculated to include unrecognized capacity. |
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (continued)
For the Periods Ended December 2013 through 2017
Southern Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | |
| 2017 |
| | 2016(a) |
| | 2015 |
| | 2014 |
| | 2013 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 27.0 |
| | 30.3 |
| | 32.3 |
| | 39.3 |
| | 36.9 |
|
Nuclear | 14.5 |
| | 14.5 |
| | 15.2 |
| | 14.8 |
| | 15.5 |
|
Oil and gas | 41.9 |
| | 41.7 |
| | 42.7 |
| | 37.0 |
| | 37.2 |
|
Hydro | 2.1 |
| | 2.1 |
| | 2.6 |
| | 2.5 |
| | 3.9 |
|
Other | 5.4 |
| | 2.4 |
| | 0.8 |
| | 0.4 |
| | 0.1 |
|
Purchased power | 9.1 |
| | 9.0 |
| | 6.4 |
| | 6.0 |
| | 6.4 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Gas Sales Volumes (mmBtu in millions): | | | | | | | | | |
Firm | 667 |
| | 296 |
| | — |
| | — |
| | — |
|
Interruptible | 95 |
| | 53 |
| | — |
| | — |
| | — |
|
Total | 762 |
| | 349 |
| | — |
| | — |
| | — |
|
Traditional Electric Operating Company Customers (year-end) (in thousands): | | | | | | | | | |
Residential | 4,011 |
| | 3,970 |
| | 3,928 |
| | 3,890 |
| | 3,859 |
|
Commercial(b) | 599 |
| | 595 |
| | 590 |
| | 586 |
| | 582 |
|
Industrial(b) | 18 |
| | 17 |
| | 17 |
| | 17 |
| | 17 |
|
Other | 12 |
| | 11 |
| | 11 |
| | 11 |
| | 9 |
|
Total electric customers | 4,640 |
| | 4,593 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Gas distribution operations customers | 4,623 |
| | 4,586 |
| | — |
| | — |
| | — |
|
Total utility customers | 9,263 |
| | 9,179 |
| | 4,546 |
| | 4,504 |
| | 4,467 |
|
Employees (year-end) | 31,344 |
| | 32,015 |
| | 26,703 |
| | 26,369 |
| | 26,300 |
|
|
| |
(a) | The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 12 under "Merger with Southern Company Gas" for additional information. |
(b) | A reclassification of customers from commercial to industrial is reflected for years 2013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material. |
ALABAMA POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Alabama Power Company 2017 Annual Report
The management of Alabama Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017.
/s/ Mark A. Crosswhite
Mark A. Crosswhite
Chairman, President, and Chief Executive Officer
/s/ Philip C. Raymond
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Alabama Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Alabama Power Company (the Company) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2017 and 2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-186 to II-231) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 20, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
AFUDC | Allowance for funds used during construction |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
DOE | U.S. Department of Energy |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
NDR | Natural Disaster Reserve |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreement |
PSC | Public Service Commission |
Rate CNP | Rate Certificated New Plant |
Rate CNP Compliance | Rate Certificated New Plant Compliance |
Rate CNP PPA | Rate Certificated New Plant Power Purchase Agreement |
Rate ECR | Rate Energy Cost Recovery |
Rate NDR | Rate Natural Disaster Reserve |
Rate RSE | Rate Stabilization and Equalization plan |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
Southern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power Company, Georgia Power, Gulf Power, and Mississippi Power |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power Company 2017 Annual Report
OVERVIEW
Business Activities
Alabama Power Company (the Company) operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. The Company has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
The Company continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance.
See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Earnings
The Company's 2017 net income after dividends on preferred and preference stock was $848 million, representing a $26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.
The Company's 2016 net income after dividends on preferred and preference stock was $822 million, representing a $37 million, or 4.7%, increase over the previous year. The increase was due primarily to an increase in retail revenues under Rate CNP Compliance, an increase in weather-related revenues, and a decrease in operations and maintenance expenses not related to fuel or Rate CNP Compliance. These increases to income were partially offset by an accrual for a Rate RSE refund, a decrease in AFUDC equity, and an increase in depreciation.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
RESULTS OF OPERATIONS
A condensed income statement for the Company follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 | | 2016 |
| (in millions) |
Operating revenues | $ | 6,039 |
| | $ | 150 |
| | $ | 121 |
|
Fuel | 1,225 |
| | (72 | ) | | (45 | ) |
Purchased power | 328 |
| | (6 | ) | | (17 | ) |
Other operations and maintenance | 1,652 |
| | 142 |
| | 9 |
|
Depreciation and amortization | 736 |
| | 33 |
| | 60 |
|
Taxes other than income taxes | 384 |
| | 4 |
| | 12 |
|
Total operating expenses | 4,325 |
| | 101 |
| | 19 |
|
Operating income | 1,714 |
| | 49 |
| | 102 |
|
Allowance for equity funds used during construction | 39 |
| | 11 |
| | (32 | ) |
Interest expense, net of amounts capitalized | 305 |
| | 3 |
| | 28 |
|
Other income (expense), net | (14 | ) | | 7 |
| | 11 |
|
Income taxes | 568 |
| | 37 |
| | 25 |
|
Net income | 866 |
| | 27 |
| | 28 |
|
Dividends on preferred and preference stock | 18 |
| | 1 |
| | (9 | ) |
Net income after dividends on preferred and preference stock | $ | 848 |
| | $ | 26 |
| | $ | 37 |
|
Operating Revenues
Operating revenues for 2017 were $6.0 billion, reflecting a $150 million increase from 2016. Details of operating revenues were as follows: |
| | | | | | | |
| Amount |
| 2017 | | 2016 |
| (in millions) |
Retail — prior year | $ | 5,322 |
| | $ | 5,234 |
|
Estimated change resulting from — | | | |
Rates and pricing | 362 |
| | 147 |
|
Sales decline | (44 | ) | | (20 | ) |
Weather | (89 | ) | | 31 |
|
Fuel and other cost recovery | (93 | ) | | (70 | ) |
Retail — current year | 5,458 |
| | 5,322 |
|
Wholesale revenues — | | | |
Non-affiliates | 276 |
| | 283 |
|
Affiliates | 97 |
| | 69 |
|
Total wholesale revenues | 373 |
| | 352 |
|
Other operating revenues | 208 |
| | 215 |
|
Total operating revenues | $ | 6,039 |
| | $ | 5,889 |
|
Percent change | 2.6 | % | | 2.1 | % |
Retail revenues in 2017 were $5.5 billion. These revenues increased $136 million, or 2.6%, in 2017 and $88 million, or 1.7%, in 2016, each as compared to the prior year. The increase in 2017 was primarily due to an increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and milder weather in the first and third quarters 2017
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
as compared to the corresponding periods in 2016. The increase in 2016 was due to an increase in revenues under Rate CNP Compliance as a result of increased net investments, partially offset by a decrease in fuel revenues and an accrual for a Rate RSE refund. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.
Fuel rates billed to customers are designed to fully recover fluctuating fuel and purchased power costs over a period of time. Fuel revenues generally have no effect on net income because they represent the recording of revenues to offset fuel and purchased power expenses. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Wholesale revenues from power sales to non-affiliated utilities were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Capacity and other | $ | 154 |
| | $ | 154 |
| | $ | 140 |
|
Energy | 122 |
| | 129 |
| | 101 |
|
Total non-affiliated | $ | 276 |
| | $ | 283 |
| | $ | 241 |
|
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy.
In 2017, wholesale revenues from sales to non-affiliates decreased $7 million, or 2.5%, as compared to the prior year. In 2016, wholesale revenues from sales to non-affiliates increased $42 million, or 17.4%, as compared to the prior year primarily due to a $28 million increase in revenues from energy sales and a $14 million increase in capacity revenues. In 2016, KWH sales increased 33.3% primarily due to a new contract that became effective in the first quarter 2016 partially offset by a 12.1% decrease in the price of energy due to lower natural gas prices.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through the Company's energy cost recovery clause.
In 2017, wholesale revenues from sales to affiliates increased $28 million, or 40.6%, as compared to the prior year. In 2017, KWH sales increased 31.1% as a result of supporting Southern Company system transmission reliability and a 6.9% increase in the price of energy primarily due to higher natural gas prices. In 2016, wholesale revenues from sales to affiliates decreased $15 million, or 17.9%, as compared to the prior year. In 2016, KWH sales decreased 15.7% as a result of lower-cost generation available in the Southern Company system and a 2.6% decrease in the price of energy primarily due to lower natural gas prices.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2017 and the percent change from the prior year were as follows:
|
| | | | | | | | | | | | | | |
| Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in billions) | | | | | | | | |
Residential | 17.2 |
| | (6.1 | )% | | 1.4 | % | | (1.2 | )% | | (0.5 | )% |
Commercial | 13.6 |
| | (3.4 | ) | | (0.1 | ) | | (1.3 | ) | | (0.5 | ) |
Industrial | 22.7 |
| | 1.7 |
| | (4.6 | ) | | 1.7 |
| | (4.6 | ) |
Other | 0.2 |
| | (5.0 | ) | | 3.8 |
| | (5.0 | ) | | 3.8 |
|
Total retail | 53.7 |
| | (2.3 | ) | | (1.5 | ) | | (0.1 | )% | | (2.2 | )% |
Wholesale | | | | | | | | | |
Non-affiliates | 5.5 |
| | (6.5 | ) | | 37.1 |
| | | | |
Affiliates | 4.2 |
| | 31.1 |
| | (15.7 | ) | | | | |
Total wholesale | 9.7 |
| | 6.6 |
| | 12.5 |
| | | | |
Total energy sales | 63.4 |
| | (1.0 | )% | | 0.3 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2017 were 2.3% lower than in 2016. Residential sales and commercial sales decreased 6.1% and 3.4% in 2017, respectively, primarily due to milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016. Weather-adjusted residential sales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales increased 1.7% in 2017 as compared to 2016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors offset by the pipelines and paper sectors.
Retail energy sales in 2016 were 1.5% lower than in 2015. Residential sales increased 1.4% primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015. Commercial sales remained flat in 2016. Weather-adjusted residential sales were flat in 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Industrial sales decreased 4.6% in 2016 compared to 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemical, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global growth conditions constrained growth in the industrial sector in 2016.
See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies as related to changes in price and KWH sales.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Details of the Company's generation and purchased power were as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Total generation (in billions of KWHs) | 60.3 |
| | 60.2 |
| | 60.9 |
|
Total purchased power (in billions of KWHs) | 6.4 |
| | 7.1 |
| | 6.3 |
|
Sources of generation (percent) — | | | | | |
Coal | 50 |
| | 53 |
| | 54 |
|
Nuclear | 24 |
| | 23 |
| | 24 |
|
Gas | 20 |
| | 19 |
| | 16 |
|
Hydro | 6 |
| | 5 |
| | 6 |
|
Cost of fuel, generated (in cents per net KWH) — | | | | | |
Coal | 2.60 |
| | 2.75 |
| | 2.83 |
|
Nuclear | 0.75 |
| | 0.78 |
| | 0.81 |
|
Gas | 2.72 |
| | 2.67 |
| | 2.94 |
|
Average cost of fuel, generated (in cents per net KWH)(a) | 2.14 |
| | 2.26 |
| | 2.34 |
|
Average cost of purchased power (in cents per net KWH)(b) | 5.29 |
| | 4.80 |
| | 5.66 |
|
|
| |
(a) | KWHs generated by hydro are excluded from the average cost of fuel, generated. |
(b) | Average cost of purchased power includes fuel, energy, and transmission purchased by the Company for tolling agreements where power is generated by the provider. |
Fuel and purchased power expenses were $1.55 billion in 2017, a decrease of $78 million, or 4.8%, compared to 2016. The decrease was primarily due to a $67 million net decrease related to the volume of KWHs generated and purchased and a $42 million decrease in the average cost of fuel, partially offset by a $31 million increase in the average cost of purchased power.
Fuel and purchased power expenses were $1.63 billion in 2016, a decrease of $62 million, or 3.7%, compared to 2015. The decrease was primarily due to a $61 million decrease in the average cost of purchased power, and a $59 million decrease in the average cost of fuel, partially offset by a $49 million increase related to the volume of KWHs purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through the Company's energy cost recovery clause. The Company, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate ECR" for additional information.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Fuel
Fuel expenses were $1.2 billion in 2017, a decrease of $72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of KWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas. Fuel expenses were $1.3 billion in 2016, a decrease of $45 million, or 3.4%, compared to 2015. The decrease was primarily due to a 9.2% decrease in the average cost of KWHs generated by natural gas, which excludes tolling agreements, a 4.2% and 3.9% decrease in the volume of KWHs generated by nuclear fuel and coal, respectively, and a 3.7% decrease in the average cost of KWHs generated by nuclear fuel, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.
Purchased Power – Affiliates
Purchased power expense from affiliates was $158 million in 2017, a decrease of $10 million, or 6.0%, compared to 2016. This decrease was primarily due to a 17.2% decrease in the amount of energy purchased due to milder weather partially offset by a 13.9% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from affiliates was $168 million in 2016, a decrease of $12 million, or 6.7%, compared to 2015. This decrease was primarily due to a
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
20.7% decrease in the average cost per KWH purchased due to lower natural gas prices, partially offset by a 17.5% increase in the amount of energy purchased due to the availability of lower-cost generation compared to the Company's owned generation.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
In 2017, other operations and maintenance expenses increased $142 million, or 9.4%, as compared to the prior year. Distribution and transmission expenses increased $58 million primarily due to vegetation management expenses. Generation costs increased $38 million primarily due to outage costs. Employee benefit costs, including pension costs, increased $22 million.
In 2016, other operations and maintenance expenses increased $9 million, or 0.6%, as compared to the prior year. Steam production costs increased $28 million primarily due to the timing of generation operating expenses. Transmission and distribution expenses increased $10 million and $7 million, respectively, primarily due to additional vegetation management and other maintenance expenses. These increases were partially offset by a decrease of $32 million in employee benefit costs, including pension costs. The increases in operations and maintenance expenses were primarily Rate CNP compliance-related costs and therefore had no significant impact to net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate CNP Compliance" herein for additional information.
See Note 2 to the financial statements under "Pension Plans" for additional information.
Depreciation and Amortization
Depreciation and amortization increased $33 million, or 4.7%, in 2017 as compared to the prior year primarily due to additional plant in service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by a decrease in distribution-related depreciation rates. See Note 1 to the financial statements under "Depreciation and Amortization" for additional information. Depreciation and amortization increased $60 million, or 9.3%, in 2016 as compared to the prior year primarily due to compliance-related steam projects placed in service.
Taxes Other Than Income Taxes
Taxes other than income taxes increased $4 million, or 1.1%, in 2017 as compared to the prior year. In 2016, taxes other than income taxes increased $12 million, or 3.3% in 2016 as compared to the prior year. The increase was primarily due to increases in state and municipal utility license tax bases primarily due to an increase in retail revenues. In addition, ad valorem taxes increased primarily due to an increase in assessed value of property.
Allowance for Equity Funds Used During Construction
AFUDC equity increased $11 million, or 39.3%, in 2017 as compared to the prior year. The increase was primarily associated with steam, transmission, and nuclear construction projects. AFUDC equity decreased $32 million, or 53.3%, in 2016 as compared to the prior year. The decrease was primarily associated with steam generation capital projects being placed in service. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased $3 million, or 1.0%, in 2017 as compared to the prior year. Interest expense, net of amounts capitalized increased $28 million, or 10.2%, in 2016 as compared to the prior year primarily due to an increase in debt outstanding and a reduction in the amounts capitalized. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.
Other Income (Expense), Net
Other income (expense), net increased $7 million, or 33.3%, in 2017 as compared to the prior year primarily due to increases in unregulated lighting services. Other income (expense), net increased $11 million, or 34.4%, in 2016 as compared to the prior year primarily due to a decrease in donations, partially offset by a decrease in sales of non-utility property.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Income Taxes
Income taxes increased $37 million, or 7.0%, in 2017 as compared to the prior year primarily due to higher pre-tax earnings, an increase in prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to income taxes as a result of Tax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information. Income taxes increased $25 million, or 4.9%, in 2016 as compared to the prior year primarily due to higher pre-tax earnings.
Dividends on Preferred and Preference Stock
Dividends on preferred and preference stock increased $1 million, or 5.9%, in 2017 as compared to the prior year. Dividends on preferred and preference stock decreased $9 million, or 34.6%, in 2016 as compared to the prior year. The decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements under "Redeemable Preferred and Preference Stock" for additional information.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama and to wholesale customers in the Southeast. Prices for electric service provided by the Company to retail customers are set by the Alabama PSC under cost-based regulatory principles. Prices for wholesale electric service, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's primary business of providing electric service. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the Company's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate CNP Compliance" for additional information. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.
Through 2017, the Company has invested approximately $4.7 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $491 million, $260 million, and $349 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.4 billion from 2018 through 2022, with annual totals of approximately $581 million in 2018, $110 million in 2019, $163 million in 2020, $258 million in 2021, and $268 million in 2022. These estimates do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2015, the EPA published a more stringent eight-hour ozone NAAQS. The EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are anticipated to be designated nonattainment under the 2015 ozone NAAQS. In 2010, the EPA revised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the vicinity of Company-owned SO2 sources have been designated nonattainment under the 2010 one-hour SO2 NAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance costs could result.
In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that addresses the impacts of the interstate transport of SO2 and NOX emissions from fossil fuel-fired power plants located in upwind states in the eastern half of the U.S. on air quality in downwind states. The Company has fossil fuel-fired generation subject to these requirements. In October 2016, the EPA published a final rule that revised the CSAPR seasonal NOX program, establishing more stringent NOX emissions budgets in Alabama. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States must submit a revised state implementation plan (SIP) to the EPA by July 31, 2021, demonstrating reasonable progress towards achieving visibility improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
In 2015, the EPA published a final rule requiring certain states (including Alabama) to revise or remove the provisions of their SIPs regulating excess emissions at industrial facilities, including electric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in increased operations and maintenance costs for the Company.
Water Quality
In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities in order to minimize their effects on fish and other aquatic life. The regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020. The Company continues to monitor the ELG rule and anticipates that approximately 1,000 MWs of the Company's generation will not be available after the compliance date. The ultimate impact of this rule will depend on any new rule-making that revises the limitation and applicable dates. The Company does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on the Company's operations or financial condition.
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
Coal Combustion Residuals
In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule requires CCR units to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.
The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule.
Based on cost estimates for closure in place and monitoring of ash ponds pursuant to the CCR Rule, the Company recorded AROs for each CCR unit in 2015. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Global Climate Issues
In 2015, the EPA published final rules limiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Clean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including review of the CPP and other CO2 emissions rules. On October 10, 2017, the EPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of proposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the United Nations Framework Convention on Climate Change, including the United States, adopted the Paris Agreement, which established a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its implementation by participating countries.
The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2016 GHG emissions were approximately 38 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2017 GHG emissions on the same basis is approximately 37 million metric tons of CO2 equivalent.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Retail Regulatory Matters
The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. The Company currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting the Company. See Note 1 to the financial statements and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's rate mechanisms and accounting orders.
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.
In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
Rate CNP Compliance
Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing.
Rate ECR
The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
Rate NDR
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. The regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $3 million, a $271 million decrease in regulatory assets, and a $2.0 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Alabama PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters – Rate RSE" for additional information.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Federal Tax Reform Legislation" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, approximately $200 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year and approximately $90 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
The Company is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate RSE" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $24 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in an $9 million or less change in total annual benefit expense and a $128 million or less change in projected obligations.
The Company recorded pension costs of $9 million, $11 million, and $48 million in 2017, 2016, and 2015, respectively. Postretirement benefit costs for the Company were $3 million, $4 million, and $5 million in 2017, 2016, and 2015, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and other postretirement benefit costs is capitalized based on construction-related labor charges. Pension and other postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
investing activities include investments to meet projected long-term demand requirements, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, or equity contributions from Southern Company. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's investments in the qualified pension plan and the nuclear decommissioning trust funds increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated during 2018. The Company's funding obligations for the nuclear decommissioning trust fund are based on the most recent site study, and the next study is expected to be conducted in 2018. See Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities totaled $1.8 billion for 2017, a decrease of $112 million as compared to 2016. The decrease in cash provided from operating activities was primarily due to the timing of income tax payments in 2017 and the receipt of income tax refunds in 2016 as a result of bonus depreciation, partially offset by the voluntary contribution to the qualified pension plan in 2016. Net cash provided from operating activities totaled $1.9 billion for 2016, a decrease of $193 million as compared to 2015. The decrease in cash provided from operating activities was primarily due to the collection of fuel cost recovery revenues and the voluntary contribution to the qualified pension plan, partially offset by the timing of income tax payments and refunds associated with bonus depreciation.
Net cash used for investing activities totaled $1.9 billion for 2017, $1.4 billion for 2016, and $1.5 billion for 2015. These activities were primarily related to gross property additions for environmental, steam generation, distribution, and transmission assets.
Net cash provided from financing activities totaled $163 million in 2017 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and maturities of long-term debt. Net cash used for financing activities totaled $285 million in 2016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by issuances of long-term debt and additional capital contributions from Southern Company. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for 2017 included increases of $1.3 billion in property, plant, and equipment primarily due to additions to distribution and transmission facilities and environmental and steam generation assets and $1.1 billion in long-term debt. Other significant changes included an increase of $2.0 billion in deferred credits related to income taxes and decreases of $1.9 billion in accumulated deferred income taxes primarily due to the change in tax rate resulting from Tax Reform Legislation and $0.6 billion in securities due within one year. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
The Company's ratio of common equity to total capitalization plus short-term debt was 46.3% and 46.2% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.
Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
The Company's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At December 31, 2017, the Company had approximately $544 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:
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Expires | | | | | | Expires Within One Year |
2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) |
$ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In May 2017 and September 2017, the Company amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.
Most of these bank credit arrangements, as well as the Company's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of the Company. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $854 million as of December 31, 2017. In addition, at December 31, 2017, the Company had $120 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
The Company also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. The Company may meet short-term cash needs through its commercial paper program. The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 3 |
| | 3.7 | % | | $ | 25 |
| | 1.3 | % | | $ | 223 |
|
December 31, 2016 | $ | — |
| | — | % | | $ | 16 |
| | 0.6 | % | | $ | 200 |
|
December 31, 2015 | $ | — |
| | — | % | | $ | 14 |
| | 0.2 | % | | $ | 100 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2017, 2016, and 2015. |
The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Financing Activities
In February 2017, the Company repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, the Company issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).
In September 2017, the Company issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including the Company's continuous construction program.
In October 2017, the Company repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes.
In November 2017, the Company issued $550 million aggregate principal amount of Series 2017B 3.70% Senior Notes due December 1, 2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
At December 31, 2017, the Company did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 1 |
|
At BBB- and/or Baa3 | $ | 2 |
|
Below BBB- and/or Baa3 | $ | 323 |
|
Included in these amounts are certain agreements that could require collateral in the event that either the Company or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
On January 19, 2018, Moody's revised its rating outlook for the Company from stable to negative.
While it is unclear how the credit rating agencies and regulatory authorities may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate RSE" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure at December 31, 2017 was 2.3%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $11 million at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. The Company continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at the Company's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. The Company may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of the Company's natural gas budget for that year.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | 12 |
| | $ | (54 | ) |
Contracts realized or settled | (1 | ) | | 39 |
|
Current period changes(*) | (17 | ) | | 27 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (6 | ) | | $ | 12 |
|
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, for the years ended December 31 were as follows:
|
| | | | | |
| 2017 | | 2016 |
| mmBtu Volume |
| (in millions) |
Commodity – Natural gas swaps | 64 |
| | 68 |
|
Commodity – Natural gas options | 5 |
| | 6 |
|
Total hedge volume | 69 |
| | 74 |
|
The weighted average swap contract cost above market prices was approximately $0.08 per mmBtu as of December 31, 2017 and below market prices was approximately $0.14 per mmBtu as of December 31, 2016. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the natural gas hedge gains and losses are recovered through the Company's retail energy cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are primarily Level 2 of the fair value hierarchy, at December 31, 2017 were as follows:
|
| | | | | | | | | | | |
| | | Fair Value Measurements |
| | | December 31, 2017 |
| Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 |
| (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | 6 |
| | 4 |
| | 2 |
|
Level 3 | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | 6 |
| | $ | 4 |
| | $ | 2 |
|
The Company is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $581 million for 2018, $110 million for 2019, $163 million for 2020, $258 million for 2021, and $268 million for 2022. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.3 million for 2018, $111 million for 2019, $90 million for 2020, $94 million for 2021, and $96 million for 2022. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
As a result of NRC requirements, the Company has external trust funds for nuclear decommissioning costs; however, the Company currently has no additional funding requirements. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other postretirement benefit plans, preferred stock dividends, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | — |
| | $ | 450 |
| | $ | 1,060 |
| | $ | 6,176 |
| | $ | 7,686 |
|
Interest | 304 |
| | 598 |
| | 561 |
| | 4,408 |
| | 5,871 |
|
Preferred stock dividends(b) | 15 |
| | 29 |
| | 29 |
| | — |
| | 73 |
|
Financial derivative obligations(c) | 6 |
| | 4 |
| | — |
| | — |
| | 10 |
|
Operating leases(d) | 21 |
| | 40 |
| | 24 |
| | 20 |
| | 105 |
|
Capital Lease | 1 |
| | 1 |
| | 1 |
| | 2 |
| | 5 |
|
Purchase commitments — | | | | | | | | | |
Capital(e) | 2,053 |
| | 2,972 |
| | 2,914 |
| | — |
| | 7,939 |
|
Fuel(f) | 974 |
| | 1,197 |
| | 459 |
| | 238 |
| | 2,868 |
|
Purchased power(g) | 78 |
| | 171 |
| | 186 |
| | 606 |
| | 1,041 |
|
Other(h) | 47 |
| | 73 |
| | 59 |
| | 313 |
| | 492 |
|
Pension and other postretirement benefit plans(i) | 19 |
| | 36 |
| | — |
| | — |
| | 55 |
|
Total | $ | 3,518 |
| | $ | 5,571 |
| | $ | 5,293 |
| | $ | 11,763 |
| | $ | 26,145 |
|
| |
(a) | All amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 11 to the financial statements. |
| |
(d) | Excludes PPAs that are accounted for as leases and are included in purchased power. |
| |
(e) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements which are reflected in "Fuel" and "Other," respectively. At December 31, 2017, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information. |
| |
(f) | Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(g) | Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy. |
| |
(h) | Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;
investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the inherent risks involved in operating nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Alabama Power Company 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Retail revenues | $ | 5,458 |
| | $ | 5,322 |
| | $ | 5,234 |
|
Wholesale revenues, non-affiliates | 276 |
| | 283 |
| | 241 |
|
Wholesale revenues, affiliates | 97 |
| | 69 |
| | 84 |
|
Other revenues | 208 |
| | 215 |
| | 209 |
|
Total operating revenues | 6,039 |
| | 5,889 |
| | 5,768 |
|
Operating Expenses: | | | | | |
Fuel | 1,225 |
| | 1,297 |
| | 1,342 |
|
Purchased power, non-affiliates | 170 |
| | 166 |
| | 171 |
|
Purchased power, affiliates | 158 |
| | 168 |
| | 180 |
|
Other operations and maintenance | 1,652 |
| | 1,510 |
| | 1,501 |
|
Depreciation and amortization | 736 |
| | 703 |
| | 643 |
|
Taxes other than income taxes | 384 |
| | 380 |
| | 368 |
|
Total operating expenses | 4,325 |
| | 4,224 |
| | 4,205 |
|
Operating Income | 1,714 |
| | 1,665 |
| | 1,563 |
|
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 39 |
| | 28 |
| | 60 |
|
Interest expense, net of amounts capitalized | (305 | ) | | (302 | ) | | (274 | ) |
Other income (expense), net | (14 | ) | | (21 | ) | | (32 | ) |
Total other income and (expense) | (280 | ) | | (295 | ) | | (246 | ) |
Earnings Before Income Taxes | 1,434 |
| | 1,370 |
| | 1,317 |
|
Income taxes | 568 |
| | 531 |
| | 506 |
|
Net Income | 866 |
| | 839 |
| | 811 |
|
Dividends on Preferred and Preference Stock | 18 |
| | 17 |
| | 26 |
|
Net Income After Dividends on Preferred and Preference Stock | $ | 848 |
| | $ | 822 |
| | $ | 785 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $(1), $(1), and $(3), respectively | 1 |
| | (2 | ) | | (5 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $1, respectively | 3 |
| | 4 |
| | 2 |
|
Total other comprehensive income (loss) | 4 |
| | 2 |
| | (3 | ) |
Comprehensive Income | $ | 870 |
| | $ | 841 |
| | $ | 808 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report |
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 866 |
| | $ | 839 |
| | $ | 811 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 888 |
| | 844 |
| | 780 |
|
Deferred income taxes | 409 |
| | 407 |
| | 388 |
|
Allowance for equity funds used during construction | (39 | ) | | (28 | ) | | (60 | ) |
Pension and postretirement funding | (2 | ) | | (133 | ) | | — |
|
Other, net | (14 | ) | | (102 | ) | | 15 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (168 | ) | | 94 |
| | (160 | ) |
-Other current assets | (16 | ) | | 1 |
| | 40 |
|
-Accounts payable | 71 |
| | 73 |
| | 3 |
|
-Accrued taxes | (84 | ) | | 93 |
| | 138 |
|
-Retail fuel cost over recovery | (76 | ) | | (162 | ) | | 191 |
|
-Other current liabilities | 2 |
| | 23 |
| | (4 | ) |
Net cash provided from operating activities | 1,837 |
| | 1,949 |
| | 2,142 |
|
Investing Activities: | | | | | |
Property additions | (1,882 | ) | | (1,272 | ) | | (1,367 | ) |
Nuclear decommissioning trust fund purchases | (237 | ) | | (352 | ) | | (439 | ) |
Nuclear decommissioning trust fund sales | 237 |
| | 351 |
| | 438 |
|
Cost of removal net of salvage | (112 | ) | | (94 | ) | | (71 | ) |
Change in construction payables | 161 |
| | (37 | ) | | (15 | ) |
Other investing activities | (43 | ) | | (34 | ) | | (34 | ) |
Net cash used for investing activities | (1,876 | ) | | (1,438 | ) | | (1,488 | ) |
Financing Activities: | | | | | |
Increase in notes payable, net | 3 |
| | — |
| | — |
|
Proceeds — | | | | | |
Senior notes | 1,100 |
| | 400 |
| | 975 |
|
Preferred stock | 250 |
| | — |
| | — |
|
Pollution control revenue bonds | — |
| | — |
| | 80 |
|
Other long-term debt | — |
| | 45 |
| | — |
|
Capital contributions from parent company | 361 |
| | 260 |
| | 22 |
|
Redemptions and repurchases — | | | | | |
Senior notes | (525 | ) | | (200 | ) | | (650 | ) |
Preferred and preference stock | (238 | ) | | — |
| | (412 | ) |
Pollution control revenue bonds | (36 | ) | | — |
| | (134 | ) |
Payment of common stock dividends | (714 | ) | | (765 | ) | | (571 | ) |
Other financing activities | (38 | ) | | (25 | ) | | (43 | ) |
Net cash provided from (used for) financing activities | 163 |
| | (285 | ) | | (733 | ) |
Net Change in Cash and Cash Equivalents | 124 |
| | 226 |
| | (79 | ) |
Cash and Cash Equivalents at Beginning of Year | 420 |
| | 194 |
| | 273 |
|
Cash and Cash Equivalents at End of Year | $ | 544 |
| | $ | 420 |
| | $ | 194 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $15, $11, and $22 capitalized, respectively) | $ | 285 |
| | $ | 277 |
| | $ | 250 |
|
Income taxes (net of refunds) | 236 |
| | (108 | ) | | 121 |
|
Noncash transactions — Accrued property additions at year-end | 245 |
| | 84 |
| | 121 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 544 |
| | $ | 420 |
|
Receivables — | | | |
Customer accounts receivable | 355 |
| | 348 |
|
Unbilled revenues | 162 |
| | 146 |
|
Affiliated | 43 |
| | 40 |
|
Other accounts and notes receivable | 55 |
| | 27 |
|
Accumulated provision for uncollectible accounts | (9 | ) | | (10 | ) |
Fossil fuel stock | 184 |
| | 205 |
|
Materials and supplies | 458 |
| | 435 |
|
Other regulatory assets, current | 124 |
| | 149 |
|
Other current assets | 90 |
| | 45 |
|
Total current assets | 2,006 |
| | 1,805 |
|
Property, Plant, and Equipment: | | | |
In service | 27,326 |
| | 26,031 |
|
Less: Accumulated provision for depreciation | 9,563 |
| | 9,112 |
|
Plant in service, net of depreciation | 17,763 |
| | 16,919 |
|
Nuclear fuel, at amortized cost | 339 |
| | 336 |
|
Construction work in progress | 908 |
| | 491 |
|
Total property, plant, and equipment | 19,010 |
| | 17,746 |
|
Other Property and Investments: | | | |
Equity investments in unconsolidated subsidiaries | 67 |
| | 66 |
|
Nuclear decommissioning trusts, at fair value | 903 |
| | 792 |
|
Miscellaneous property and investments | 124 |
| | 112 |
|
Total other property and investments | 1,094 |
| | 970 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 239 |
| | 525 |
|
Deferred under recovered regulatory clause revenues | 54 |
| | 150 |
|
Other regulatory assets, deferred | 1,272 |
| | 1,157 |
|
Other deferred charges and assets | 189 |
| | 163 |
|
Total deferred charges and other assets | 1,754 |
| | 1,995 |
|
Total Assets | $ | 23,864 |
| | $ | 22,516 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholder's Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | — |
| | $ | 561 |
|
Accounts payable — | | | |
Affiliated | 327 |
| | 297 |
|
Other | 585 |
| | 433 |
|
Customer deposits | 92 |
| | 88 |
|
Accrued taxes — | | | |
Accrued income taxes | 9 |
| | 45 |
|
Other accrued taxes | 45 |
| | 42 |
|
Accrued interest | 77 |
| | 78 |
|
Accrued compensation | 205 |
| | 193 |
|
Other regulatory liabilities, current | 1 |
| | 85 |
|
Other current liabilities | 59 |
| | 76 |
|
Total current liabilities | 1,400 |
| | 1,898 |
|
Long-Term Debt (See accompanying statements) | 7,628 |
| | 6,535 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 2,760 |
| | 4,654 |
|
Deferred credits related to income taxes | 2,082 |
| | 65 |
|
Accumulated deferred ITCs | 112 |
| | 110 |
|
Employee benefit obligations | 304 |
| | 300 |
|
Asset retirement obligations | 1,702 |
| | 1,503 |
|
Other cost of removal obligations | 609 |
| | 684 |
|
Other regulatory liabilities, deferred | 84 |
| | 100 |
|
Other deferred credits and liabilities | 63 |
| | 63 |
|
Total deferred credits and other liabilities | 7,716 |
| | 7,479 |
|
Total Liabilities | 16,744 |
| | 15,912 |
|
Redeemable Preferred Stock (See accompanying statements) | 291 |
| | 85 |
|
Preference Stock (See accompanying statements) | — |
| | 196 |
|
Common Stockholder's Equity (See accompanying statements) | 6,829 |
| | 6,323 |
|
Total Liabilities and Stockholder's Equity | $ | 23,864 |
| | $ | 22,516 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | |
Long-term debt payable to affiliated trusts — | | | | | | | |
Variable rate (4.44% at 12/31/17) due 2042 | $ | 206 |
| | $ | 206 |
| | | | |
Long-term notes payable — | | | | | | | |
5.50% to 5.55% due 2017 | — |
| | 525 |
| | | | |
5.125% due 2019 | 200 |
| | 200 |
| | | | |
3.375% due 2020 | 250 |
| | 250 |
| | | | |
2.38% to 3.95% due 2021 | 220 |
| | 220 |
| | | | |
2.45% to 5.875% due 2022 | 750 |
| | 200 |
| | | | |
2.80% to 6.125% due 2023-2047 | 4,975 |
| | 4,425 |
| | | | |
Variable rates (2.55% to 2.786% at 12/31/17) due 2021 | 25 |
| | 25 |
| | | | |
Total long-term notes payable | 6,420 |
| | 5,845 |
| | | | |
Other long-term debt — | | | | | | | |
Pollution control revenue bonds — | | | | | | | |
1.625% to 1.85% due 2034 | 207 |
| | 207 |
| | | | |
Variable rates (0.77% to 0.79% at 1/1/17) due 2017 | — |
| | 36 |
| | | | |
Variable rates (1.86% to 1.87% at 12/31/17) due 2021 | 65 |
| | 65 |
| | | | |
Variable rates (1.70% to 1.87% at 12/31/17) due 2024-2038 | 788 |
| | 788 |
| | | | |
Total other long-term debt | 1,060 |
| | 1,096 |
| | | | |
Capitalized lease obligations | 4 |
| | 4 |
| | | | |
Unamortized debt premium (discount), net | (11 | ) | | (9 | ) | | | | |
Unamortized debt issuance expense | (51 | ) | | (46 | ) | | | | |
Total long-term debt (annual interest requirement — $305 million) | 7,628 |
| | 7,096 |
| | | | |
Less amount due within one year | — |
| | 561 |
| | | | |
Long-term debt excluding amount due within one year | 7,628 |
| | 6,535 |
| | 51.7 | % | | 49.7 | % |
Redeemable Preferred Stock: | | | | | | | |
Cumulative redeemable preferred stock | | | | | | | |
$100 par or stated value — 4.20% to 4.92% | | | | | | | |
Authorized — 3,850,000 shares | | | | | | | |
Outstanding — 475,115 shares | 48 |
| | 48 |
| | | | |
$1 par value — | | | | | | | |
Authorized — 27,500,000 shares | | | | | | | |
Outstanding — 2017: 5.00% — 10,000,000 shares: $25 stated value | | | | | | | |
— 2016: 5.83% — 1,520,000 shares: $25 stated value | | | | | | | |
(annual dividend requirement — $15 million) | 243 |
| | 37 |
| | | | |
Total redeemable preferred stock | 291 |
| | 85 |
| | 2.0 |
| | 0.7 |
|
Preference Stock: | | | | | | | |
$1 par value — 6.45% to 6.50% | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | |
Outstanding — 2017: no shares | | | | | | | |
— 2016: 8,000,000 shares (non-cumulative): $25 stated value | — |
| | 196 |
| | — | | 1.5 |
Common Stockholder's Equity: | | | | | | | |
Common stock, par value $40 per share — | | | | | | | |
Authorized — 40,000,000 shares | | | | | | | |
Outstanding — 30,537,500 shares | 1,222 |
| | 1,222 |
| | | | |
Paid-in capital | 2,986 |
| | 2,613 |
| | | | |
Retained earnings | 2,647 |
| | 2,518 |
| | | | |
Accumulated other comprehensive loss | (26 | ) | | (30 | ) | | | | |
Total common stockholder's equity | 6,829 |
| | 6,323 |
| | 46.3 |
| | 48.1 |
|
Total Capitalization | $ | 14,748 |
| | $ | 13,139 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) |
Balance at December 31, 2014 | 31 |
| | $ | 1,222 |
| | $ | 2,304 |
| | $ | 2,255 |
| | $ | (29 | ) | | $ | 5,752 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 785 |
| | — |
| | 785 |
|
Capital contributions from parent company | — |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (3 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (571 | ) | | — |
| | (571 | ) |
Other | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
Balance at December 31, 2015 | 31 |
| | 1,222 |
| | 2,341 |
| | 2,461 |
| | (32 | ) | | 5,992 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 822 |
| | — |
| | 822 |
|
Capital contributions from parent company | — |
| | — |
| | 272 |
| | — |
| | — |
| | 272 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (765 | ) | | — |
| | (765 | ) |
Balance at December 31, 2016 | 31 |
| | 1,222 |
| | 2,613 |
| | 2,518 |
| | (30 | ) | | 6,323 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 848 |
| | — |
| | 848 |
|
Capital contributions from parent company | — |
| | — |
| | 373 |
| | — |
| | — |
| | 373 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (714 | ) | | — |
| | (714 | ) |
Other | — |
| | — |
| | — |
| | (5 | ) | | — |
| | (5 | ) |
Balance at December 31, 2017 | 31 |
| | $ | 1,222 |
| | $ | 2,986 |
| | $ | 2,647 |
| | $ | (26 | ) | | $ | 6,829 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Alabama Power Company 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Alabama Power Company 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Alabama Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary.
The Company is subject to regulation by the FERC and the Alabama PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to cellular towers, railcars, and a PPA where the Company is the lessee and outdoor lighting and to land where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $479 million, $460 million, and $438 million during 2017, 2016, and 2015, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935,
NOTES (continued)
Alabama Power Company 2017 Annual Report
as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment.
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $248 million, $249 million, and $243 million during 2017, 2016, and 2015, respectively.
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which totaled $9 million in 2017, $13 million in 2016, and $11 million in 2015. Mississippi Power also reimbursed the Company for any direct fuel purchases delivered from one of the Company's transfer facilities. There were no such fuel purchases in 2017 and 2016 and $8 million in 2015. See Note 4 for additional information.
The Company has an agreement with Gulf Power under which the Company made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Autauga County, Alabama. Under a related tariff, the Company received $11 million in 2017, $12 million in 2016, and $14 million in 2015 and expects to recover a total of approximately $61 million from 2018 through 2023 from Gulf Power.
In September 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were approximately $9 million in 2017 and $2 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
The Company has agreements with PowerSecure for services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs for these services amounted to approximately $11 million for 2017 and were immaterial for 2016.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2017, 2016, or 2015.
Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO.
The traditional electric operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Regulatory Assets and Liabilities
The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 | | 2016 | | Note |
| (in millions) | | |
Retiree benefit plans | $ | 946 |
| | $ | 947 |
| | (i,j) |
Deferred income tax charges | 240 |
| | 526 |
| | (a,k,n) |
Regulatory clauses | 142 |
| | — |
| | (m) |
Vacation pay | 70 |
| | 69 |
| | (c,j) |
Loss on reacquired debt | 62 |
| | 68 |
| | (b) |
Nuclear outage | 56 |
| | 70 |
| | (d) |
Remaining net book value of retired assets | 54 |
| | 69 |
| | (l) |
Under/(over) recovered regulatory clause revenues | 53 |
| | 76 |
| | (d) |
Other regulatory assets | 51 |
| | 50 |
| | (f) |
Fuel-hedging losses | 7 |
| | 1 |
| | (e,j) |
Deferred income tax credits | (2,082 | ) | | (65 | ) | | (a,n) |
Other cost of removal obligations | (609 | ) | | (684 | ) | | (a) |
Natural disaster reserve | (38 | ) | | (69 | ) | | (h) |
Asset retirement obligations | (33 | ) | | 12 |
| | (a) |
Other regulatory liabilities | (7 | ) | | (23 | ) | | (e,g) |
Total regulatory assets (liabilities), net | $ | (1,088 | ) | | $ | 1,047 |
| | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax credits are amortized over the related property lives, which may range up to 50 years. Asset retirement and other cost of removal assets and liabilities will be settled and trued up following completion of the related activities. |
| |
(b) | Recovered over the remaining life of the original issue, which may range up to 50 years. |
| |
(c) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(d) | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. See Note 3 under "Retail Regulatory Matters" for additional information. |
| |
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three and a half years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. |
| |
(f) | Comprised of components including generation site selection/evaluation costs, PPA capacity (to be recovered over the next 12 months), and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. |
| |
(g) | Comprised of components including mine reclamation and remediation liabilities and fuel-hedging gains. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. |
| |
(h) | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. |
| |
(i) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(k) | Included in the deferred income tax charges are $13 million for 2017 and $16 million for 2016 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. |
| |
(l) | Recorded and amortized as approved by the Alabama PSC for a period up to 11 years. |
| |
(m) | Established per an order from the Alabama PSC issued on February 17, 2017 and will be amortized concurrently with the effective date of the Company's next depreciation study. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information. |
| |
(n) | As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization. The recovery and amortization of these amounts will be established consistent with guidance provided by the Alabama PSC. See Note 5 for additional information. |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that
NOTES (continued)
Alabama Power Company 2017 Annual Report
are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.
Revenues
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company and the Alabama PSC continuously monitor the under/over recovered balances. The Company files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP Compliance" for additional information.
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Company's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Generation | $ | 14,213 |
| | $ | 13,551 |
|
Transmission | 4,119 |
| | 3,921 |
|
Distribution | 7,034 |
| | 6,707 |
|
General | 1,948 |
| | 1,840 |
|
Plant acquisition adjustment | 12 |
| | 12 |
|
Total plant in service | $ | 27,326 |
| | $ | 26,031 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders.
Nuclear Outage Accounting Order
In accordance with an Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over a subsequent 18-month period with
NOTES (continued)
Alabama Power Company 2017 Annual Report
the fall outage costs amortization beginning in January of the following year and the spring outage costs amortization beginning in July of the same year.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.9% in 2017, 3% in 2016, and 2.9% in 2015. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and approved by the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
In 2016, the Company submitted an updated depreciation study to the FERC and received authorization to use the recommended rates beginning January 2017. The study was also provided to the Alabama PSC.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley, and facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.
Details of the AROs included in the balance sheets are as follows:
|
| | | | | | | | | |
| 2017 | | | 2016 | |
| (in millions) | |
Balance at beginning of year | $ | 1,533 |
| | | $ | 1,448 |
| |
Liabilities incurred | — |
| | | 5 |
| |
Liabilities settled | (26 | ) | | | (25 | ) | |
Accretion | 77 |
| | | 73 |
| |
Cash flow revisions | 125 |
| | | 32 |
| |
Balance at end of year | $ | 1,709 |
| | | $ | 1,533 |
| |
The increase in liabilities incurred and cash flow revisions in 2017 is primarily due to updated cost estimates related to the closure of ash ponds and landfills. The increase in 2016 is primarily related to changes in ash pond closure strategy.
NOTES (continued)
Alabama Power Company 2017 Annual Report
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
At December 31, 2017, investment securities in the Funds totaled $902 million, consisting of equity securities of $644 million, debt securities of $223 million, and $35 million of other securities. At December 31, 2016, investment securities in the Funds totaled $790 million, consisting of equity securities of $552 million, debt securities of $208 million, and $30 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases.
Sales of the securities held in the Funds resulted in cash proceeds of $237 million, $351 million, and $438 million in 2017, 2016, and 2015, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $125 million, which included $98 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $76 million, which included $34 million related to unrealized gains on securities held in the Funds at December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $8 million, which included $57 million related to unrealized losses on securities held in the Funds at December 31, 2015. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
Amounts previously recorded in internal reserves are being transferred into the Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
At December 31, the accumulated provisions for decommissioning were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
External trust funds | $ | 902 |
| | $ | 790 |
|
Internal reserves | 18 |
| | 19 |
|
Total | $ | 920 |
| | $ | 809 |
|
NOTES (continued)
Alabama Power Company 2017 Annual Report
Site study cost is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2017 based on the most current study performed in 2013 for Plant Farley are as follows:
|
| | | |
Decommissioning periods: | |
Beginning year | 2037 |
|
Completion year | 2076 |
|
| (in millions) |
Site study costs: | |
Radiated structures | $ | 1,362 |
|
Non-radiated structures | 80 |
|
Total site study costs | $ | 1,442 |
|
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2018.
Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Allowance for Funds Used During Construction
The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.3% in 2017, 8.4% in 2016, and 8.7% in 2015. AFUDC, net of income taxes, as a percentage of net income after dividends on preferred and preference stock was 5.7% in 2017, 4.2% in 2016, and 9.3% in 2015.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.
The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2018, no other postretirement trusts contributions are expected.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2017 | | 2016 | | 2015 |
Pension plans | | | | | |
Discount rate – benefit obligations | 4.44 | % | | 4.67 | % | | 4.18 | % |
Discount rate – interest costs | 3.76 |
| | 3.90 |
| | 4.18 |
|
Discount rate – service costs | 4.85 |
| | 5.07 |
| | 4.49 |
|
Expected long-term return on plan assets | 7.95 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 4.46 |
| | 4.46 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – benefit obligations | 4.27 | % | | 4.51 | % | | 4.04 | % |
Discount rate – interest costs | 3.58 |
| | 3.69 |
| | 4.04 |
|
Discount rate – service costs | 4.70 |
| | 4.96 |
| | 4.40 |
|
Expected long-term return on plan assets | 6.83 |
| | 6.83 |
| | 7.17 |
|
Annual salary increase | 4.46 |
| | 4.46 |
| | 3.59 |
|
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 | | 2016 |
Pension plans | | | |
Discount rate | 3.81 | % | | 4.44 | % |
Annual salary increase | 4.46 |
| | 4.46 |
|
Other postretirement benefit plans | | | |
Discount rate | 3.71 | % | | 4.27 | % |
Annual salary increase | 4.46 |
| | 4.46 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of eight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
|
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
NOTES (continued)
Alabama Power Company 2017 Annual Report
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 30 |
| | $ | 26 |
|
Service and interest costs | 1 |
| | 1 |
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $2.7 billion at December 31, 2017 and $2.4 billion at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 2,663 |
| | $ | 2,506 |
|
Service cost | 63 |
| | 57 |
|
Interest cost | 98 |
| | 95 |
|
Benefits paid | (120 | ) | | (109 | ) |
Actuarial (gain) loss | 294 |
| | 114 |
|
Balance at end of year | 2,998 |
| | 2,663 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 2,517 |
| | 2,279 |
|
Actual return (loss) on plan assets | 427 |
| | 206 |
|
Employer contributions | 12 |
| | 141 |
|
Benefits paid | (120 | ) | | (109 | ) |
Fair value of plan assets at end of year | 2,836 |
| | 2,517 |
|
Accrued liability | $ | (162 | ) | | $ | (146 | ) |
At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $2.9 billion and $126 million, respectively. All pension plan assets are related to the qualified pension plan.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 890 |
| | $ | 870 |
|
Other current liabilities | (12 | ) | | (12 | ) |
Employee benefit obligations | (150 | ) | | (134 | ) |
Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
NOTES (continued)
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 8 |
| | $ | 10 |
| | $ | 1 |
|
Net (gain) loss | 882 |
| | 860 |
| | 54 |
|
Regulatory assets | $ | 890 |
| | $ | 870 |
| | |
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Regulatory assets: | | | |
Beginning balance | $ | 870 |
| | $ | 822 |
|
Net (gain) loss | 64 |
| | 84 |
|
Change in prior service costs | — |
| | 7 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (2 | ) | | (3 | ) |
Amortization of net gain (loss) | (42 | ) | | (40 | ) |
Total reclassification adjustments | (44 | ) | | (43 | ) |
Total change | 20 |
| | 48 |
|
Ending balance | $ | 890 |
| | $ | 870 |
|
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 63 |
| | $ | 57 |
| | $ | 59 |
|
Interest cost | 98 |
| | 95 |
| | 106 |
|
Expected return on plan assets | (196 | ) | | (184 | ) | | (178 | ) |
Recognized net (gain) loss | 42 |
| | 40 |
| | 55 |
|
Net amortization | 2 |
| | 3 |
| | 6 |
|
Net periodic pension cost | $ | 9 |
| | $ | 11 |
| | $ | 48 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 129 |
|
2019 | 134 |
|
2020 | 139 |
|
2021 | 143 |
|
2022 | 148 |
|
2023 to 2027 | 807 |
|
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 501 |
| | $ | 505 |
|
Service cost | 6 |
| | 5 |
|
Interest cost | 17 |
| | 18 |
|
Benefits paid | (29 | ) | | (28 | ) |
Actuarial (gain) loss | 20 |
| | (1 | ) |
Retiree drug subsidy | 2 |
| | 2 |
|
Balance at end of year | 517 |
| | 501 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 367 |
| | 363 |
|
Actual return (loss) on plan assets | 60 |
| | 23 |
|
Employer contributions | 6 |
| | 7 |
|
Benefits paid | (27 | ) | | (26 | ) |
Fair value of plan assets at end of year | 406 |
| | 367 |
|
Accrued liability | $ | (111 | ) | | $ | (134 | ) |
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 63 |
| | $ | 86 |
|
Other regulatory liabilities, deferred | (7 | ) | | (10 | ) |
Employee benefit obligations | (111 | ) | | (134 | ) |
NOTES (continued)
Alabama Power Company 2017 Annual Report
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | | | | | |
| 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 11 |
| | $ | 15 |
| | $ | 4 |
|
Net (gain) loss | 45 |
| | 61 |
| | 1 |
|
Net regulatory assets | $ | 56 |
| | $ | 76 |
| | |
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Net regulatory assets (liabilities): | | | |
Beginning balance | $ | 76 |
| | $ | 82 |
|
Net (gain) loss | (15 | ) | | — |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (4 | ) | | (4 | ) |
Amortization of net gain (loss) | (1 | ) | | (2 | ) |
Total reclassification adjustments | (5 | ) | | (6 | ) |
Total change | (20 | ) | | (6 | ) |
Ending balance | $ | 56 |
| | $ | 76 |
|
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 6 |
| | $ | 5 |
| | $ | 6 |
|
Interest cost | 17 |
| | 18 |
| | 20 |
|
Expected return on plan assets | (25 | ) | | (25 | ) | | (26 | ) |
Net amortization | 5 |
| | 6 |
| | 5 |
|
Net periodic postretirement benefit cost | $ | 3 |
| | $ | 4 |
| | $ | 5 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2018 | $ | 31 |
| | $ | (2 | ) | | $ | 29 |
|
2019 | 32 |
| | (2 | ) | | 30 |
|
2020 | 33 |
| | (3 | ) | | 30 |
|
2021 | 34 |
| | (3 | ) | | 31 |
|
2022 | 35 |
| | (3 | ) | | 32 |
|
2023 to 2027 | 173 |
| | (14 | ) | | 159 |
|
NOTES (continued)
Alabama Power Company 2017 Annual Report
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targeted mix of assets for each plan, is presented below:
|
| | | | | | | | |
| Target | | 2017 | | 2016 |
Pension plan assets: | | | | | |
Domestic equity | 26 | % | | 31 | % | | 29 | % |
International equity | 25 |
| | 25 |
| | 22 |
|
Fixed income | 23 |
| | 24 |
| | 29 |
|
Special situations | 3 |
| | 1 |
| | 2 |
|
Real estate investments | 14 |
| | 13 |
| | 13 |
|
Private equity | 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | |
Domestic equity | 42 | % | | 44 | % | | 44 | % |
International equity | 22 |
| | 22 |
| | 20 |
|
Domestic fixed income | 28 |
| | 28 |
| | 29 |
|
Special situations | 1 |
| | — |
| | 1 |
|
Real estate investments | 4 |
| | 4 |
| | 4 |
|
Private equity | 3 |
| | 2 |
| | 2 |
|
Total | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2017 and 2016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
NOTES (continued)
Alabama Power Company 2017 Annual Report
The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 572 |
| | $ | 276 |
| | $ | — |
| | $ | — |
| | $ | 848 |
|
International equity(*) | 370 |
| | 333 |
| | — |
| | — |
| | 703 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 200 |
| | — |
| | — |
| | 200 |
|
Mortgage- and asset-backed securities | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Corporate bonds | — |
| | 286 |
| | — |
| | — |
| | 286 |
|
Pooled funds | — |
| | 155 |
| | — |
| | — |
| | 155 |
|
Cash equivalents and other | 51 |
| | 3 |
| | — |
| | — |
| | 54 |
|
Real estate investments | 111 |
| | — |
| | — |
| | 283 |
| | 394 |
|
Special situations | — |
| | — |
| | — |
| | 43 |
| | 43 |
|
Private equity | — |
| | — |
| | — |
| | 159 |
| | 159 |
|
Total | $ | 1,104 |
| | $ | 1,255 |
| | $ | — |
| | $ | 485 |
| | $ | 2,844 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 477 |
| | $ | 220 |
| | $ | — |
| | $ | — |
| | $ | 697 |
|
International equity(*) | 292 |
| | 264 |
| | — |
| | — |
| | 556 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 140 |
| | — |
| | — |
| | 140 |
|
Mortgage- and asset-backed securities | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
Corporate bonds | — |
| | 235 |
| | — |
| | — |
| | 235 |
|
Pooled funds | — |
| | 124 |
| | — |
| | — |
| | 124 |
|
Cash equivalents and other | 236 |
| | 1 |
| | — |
| | — |
| | 237 |
|
Real estate investments | 74 |
| | — |
| | — |
| | 274 |
| | 348 |
|
Special situations | — |
| | — |
| | — |
| | 43 |
| | 43 |
|
Private equity | — |
| | — |
| | — |
| | 130 |
| | 130 |
|
Total | $ | 1,079 |
| | $ | 987 |
| | $ | — |
| | $ | 447 |
| | $ | 2,513 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Alabama Power Company 2017 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 52 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 64 |
|
International equity(*) | 16 |
| | 14 |
| | — |
| | — |
| | 30 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
Corporate bonds | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
Pooled funds | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Trust-owned life insurance | — |
| | 253 |
| | — |
| | — |
| | 253 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 12 |
| | 17 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 7 |
| | 7 |
|
Total | $ | 75 |
| | $ | 309 |
| | $ | — |
| | $ | 21 |
| | $ | 405 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 51 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 61 |
|
International equity(*) | 13 |
| | 12 |
| | — |
| | — |
| | 25 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
Corporate bonds | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Pooled funds | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Cash equivalents and other | 14 |
| | — |
| | — |
| | — |
| | 14 |
|
Trust-owned life insurance | — |
| | 220 |
| | — |
| | — |
| | 220 |
|
Real estate investments | 4 |
| | — |
| | — |
| | 12 |
| | 16 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
Total | $ | 82 |
| | $ | 264 |
| | $ | — |
| | $ | 20 |
| | $ | 366 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017, 2016, and 2015 were $23 million, $23 million, and $22 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
Environmental Matters
Environmental Remediation
The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the estimated costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require
NOTES (continued)
Alabama Power Company 2017 Annual Report
environmental remediation. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.
In 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. In 2015, the Company recovered approximately $26 million, which was applied to reduce the cost of service for the benefit of customers.
In 2014, the Company filed a lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, the Company filed an additional lawsuit against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2017 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Alabama PSC and, therefore, no material impact on the Company's net income is expected.
At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
NOTES (continued)
Alabama Power Company 2017 Annual Report
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon the Company's projected weighted cost of equity (WCE) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Retail rates remain unchanged when the WCE ranges between 5.75% and 6.21% with an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed WCE range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range.
At December 31, 2016, the Company's retail return exceeded the allowed WCE range which resulted in the Company establishing a $73 million Rate RSE refund liability. In accordance with an Alabama PSC order issued on February 14, 2017, the Company applied the full amount of the refund to reduce the under recovered balance of Rate CNP PPA as discussed further below.
Effective in January 2017, Rate RSE increased 4.48%, or $245 million annually. At December 31, 2017, the Company's actual retail return was within the allowed WCE range. On December 1, 2017, the Company made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2018. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remained unchanged for 2018.
In conjunction with Rate RSE, the Company has an established retail tariff that provides for an adjustment to customer billings to recognize the impact of a change in the statutory income tax rate. As a result of Tax Reform Legislation, the application of this tariff would reduce annual retail revenue by approximately $250 million over the remainder of 2018. The ultimate outcome of this matter cannot be determined at this time.
Rate CNP PPA
The Company's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 7, 2017, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2017 through March 31, 2018. No adjustment to Rate CNP PPA is expected in 2018. As of December 31, 2017 and 2016, the Company had an under recovered Rate CNP PPA balance of $12 million and $142 million, respectively, which is included in deferred under recovered regulatory clause revenues in the balance sheet.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company eliminated the under recovered balance in Rate CNP PPA at December 31, 2016, which totaled approximately $142 million. As discussed herein under "Rate RSE," the Company utilized the full amount of its $73 million Rate RSE refund liability to reduce the amount of the Rate CNP PPA under recovery and reclassified the remaining $69 million to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
Rate CNP Compliance
Rate CNP Compliance allows for the recovery of the Company's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. Rate CNP Compliance is based on forward-looking information
NOTES (continued)
Alabama Power Company 2017 Annual Report
and provides for the recovery of these costs pursuant to a factor that is calculated annually. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the factors associated with the Company's compliance costs for the year 2017, with any under-collected amount for prior years deemed recovered before any current year amounts. Any under recovered amounts associated with 2018 will be reflected in the 2019 filing. As of December 31, 2017 and 2016, the Company had a deferred under recovered regulatory clause revenues balance of $17 million and $9 million, respectively.
Rate ECR
The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, the Company reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of the Company's next depreciation study, which is expected to occur within the next two to four years. The Company's current depreciation study became effective January 1, 2017.
On December 5, 2017, the Alabama PSC issued a consent order that the Company leave in effect for 2018 the energy cost recovery rates which began in 2017. Therefore, the Rate ECR factor as of January 1, 2018 remained at 2.015 cents per KWH. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
At December 31, 2017, the Company's under recovered fuel costs totaled $25 million, which is included in deferred under recovered regulatory clause revenues. At December 31, 2016, the Company had an over recovered fuel balance of $76 million, which was included in other regulatory liabilities, current. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs.
Rate NDR
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional
NOTES (continued)
Alabama Power Company 2015 Annual Report
amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are
NOTES (continued)
Alabama Power Company 2017 Annual Report
incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. No such accruals were recorded or designated in any period presented.
In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. The Company expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2017 was $38 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs are beingThe regulatory asset will be amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance.
In April 2015, as part of its environmental compliance strategy, theThe Company retired Plant Gorgas Units 6 and 7 (200 MWs). and Plant Barry Unit 3 (225 MWs) in 2015. Additionally, in April 2015, the Company ceased using coal at Plant Barry Units 1 and 2 (250 MWs), in 2015, but such units will remain available on a limited basis with natural gas as the fuel source. In accordance with the joint stipulation entered in connection with a civil enforcement action by the EPA,April 2016, the Company retired Plant Barry Unit 3 (225 MWs) in August 2015 and it is no longer available for generation. The Company expects to ceasealso ceased using coal at Plant Greene County Units 1 and 2 (300 MWs)MWs representing the Company's ownership interest) and beginbegan operating those unitsUnits 1 and 2 solely on natural gas by April 2016.in June 2016 and July 2016, respectively.
In accordance with this accounting order from the Alabama PSC, the Company transferred the unrecovered plant asset balances to a regulatory assetassets at their respective retirement dates. TheThese regulatory asset will beassets are being amortized and recovered through Rate CNP Compliance over the units' remaining useful lives, as established prior to the decision for retirement. As a result,retirement; therefore, these decisions will not have aassociated with coal operations had no significant impact on the Company's financial statements.
Nuclear Waste Fund Accounting Order
In 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. The DOE formally set the fee to zero effective May 16, 2014.
In August 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, the Company was authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). On December 1, 2015, the Alabama PSC issued an order for the Company to discontinue recording the amounts recovered from customers in a regulatory liability account and transfer amounts recorded in the regulatory liability to Rate ECR. On December 1, 2015, the Company transferred $20 million from the regulatory liability to Rate ECR to offset fuel expense.
Cost of Removal Accounting Order
In accordance with an accounting order issued in November 2014 by the Alabama PSC, in December 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset accounts fully amortized and terminated as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, which were approved by the Alabama PSC in 2012 and 2013, respectively. Approximately $95 million of non-nuclear outage costs and $28 million of compliance and pension costs were fully amortized in December 2014.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. SEGCO uses natural gas as the primary fuel source for 1,000 MWs of its generating capacity. The capacity of these units is sold equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $76
NOTES (continued)
Alabama Power Company 2015 Annual Report
million in 2017, $55 million in 2016, and $76 million in 2015 $84 million in 2014, and $88 million in 2013 and is included in "Purchased power from affiliates" in the statements of income. The Company accounts for SEGCO using the equity method.
In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $25 million principal amount of pollution control revenue bonds are outstanding. The Company has guaranteed $100 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. These senior notes mature on December 1, 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guarantee.
At December 31, 2015,2017, the capitalization of SEGCO consisted of $118$95 million of equity and $125 million of long-term debt on which the annual interest requirement is $3$4 million. In addition, SEGCO had short-term debt outstanding of $52$14 million. SEGCO paid $24 million of dividends in 2017 and 2016 compared to an immaterial amount of dividends in 2015, compared to $3 million in 2014 and $7 million in 2013, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income.
SEGCO added natural gas as a fuel source for 1,000 MWs of its generating capacity in 2015. In April 2016, natural gas will become the primary fuel source. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of thean associated gas pipeline. The Company owns 14% of the pipeline with the remaining 86% owned by SEGCO.
NOTES (continued)
Alabama Power Company 2017 Annual Report
In addition to the Company's ownership of SEGCO and joint ownership of the naturalan associated gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 20152017 were as follows:
| | Facility | Total MW Capacity | | Company Ownership | | Plant in Service | | Accumulated Depreciation | | Construction Work in Progress | Total MW Capacity | | Company Ownership | | Plant in Service | | Accumulated Depreciation | | Construction Work in Progress |
| | | | | (in millions) | | | | | (in millions) |
Greene County | 500 |
| | 60.00 | % | (1) | | $ | 159 |
| | $ | 97 |
| | $ | 20 |
| 500 |
| | 60.00 | % | (1) | | $ | 172 |
| | $ | 65 |
| | $ | 2 |
|
Plant Miller | | | | | | | | | | | | | | | | | | |
Units 1 and 2 | 1,320 |
| | 91.84 | % | (2) | | 1,518 |
| | 587 |
| | 63 |
| 1,320 |
| | 91.84 | % | (2) | | 1,717 |
| | 619 |
| | 54 |
|
| |
(1) | Jointly owned with an affiliate, Mississippi Power. |
| |
(2) | Jointly owned with PowerSouth Energy Cooperative, Inc. |
The Company has contracted to operate and maintain theits jointly-owned facilities as agent for their co-owners. The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters – Rate RSE" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current | $ | 136 |
| | $ | 103 |
| | $ | 110 |
|
Deferred | 336 |
| | 339 |
| | 320 |
|
| 472 |
| | 442 |
| | 430 |
|
State — | | | | | |
Current | 23 |
| | 20 |
| | 8 |
|
Deferred | 73 |
| | 69 |
| | 68 |
|
| 96 |
| | 89 |
| | 76 |
|
Total | $ | 568 |
| | $ | 531 |
| | $ | 506 |
|
NOTES (continued)
Alabama Power Company 20152017 Annual Report
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Federal — | | | | | |
Current | $ | 110 |
| | $ | 198 |
| | $ | 243 |
|
Deferred | 320 |
| | 225 |
| | 160 |
|
| 430 |
| | 423 |
| | 403 |
|
State — | | | | | |
Current | 8 |
| | 44 |
| | 36 |
|
Deferred | 68 |
| | 45 |
| | 39 |
|
| 76 |
| | 89 |
| | 75 |
|
Total | $ | 506 |
| | $ | 512 |
| | $ | 478 |
|
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Deferred tax liabilities — | | | | | | |
Accelerated depreciation | $ | 3,917 |
| | $ | 3,429 |
| $ | 2,336 |
| | $ | 4,307 |
|
Property basis differences | 456 |
| | 457 |
| 398 |
| | 456 |
|
Premium on reacquired debt | 28 |
| | 30 |
| 16 |
| | 26 |
|
Employee benefit obligations | 200 |
| | 215 |
| 162 |
| | 201 |
|
Regulatory assets associated with employee benefit obligations | 375 |
| | 366 |
| 260 |
| | 393 |
|
Asset retirement obligations | 289 |
| | 59 |
| 220 |
| | 289 |
|
Regulatory assets associated with asset retirement obligations | 312 |
| | 285 |
| 249 |
| | 347 |
|
Other | 175 |
| | 157 |
| 147 |
| | 179 |
|
Total | 5,752 |
| | 4,998 |
| 3,788 |
| | 6,198 |
|
Deferred tax assets — | | | | | | |
Federal effect of state deferred taxes | 242 |
| | 219 |
| 143 |
| | 266 |
|
Unbilled fuel revenue | 39 |
| | 42 |
| 22 |
| | 36 |
|
Storm reserve | 23 |
| | 27 |
| 5 |
| | 21 |
|
Employee benefit obligations | 407 |
| | 400 |
| 286 |
| | 427 |
|
Other comprehensive losses | 20 |
| | 19 |
| 10 |
| | 19 |
|
Asset retirement obligations | 600 |
| | 344 |
| 469 |
| | 636 |
|
Other | 180 |
| | 90 |
| 93 |
| | 139 |
|
Total | 1,511 |
| | 1,141 |
| 1,028 |
| | 1,544 |
|
Accumulated deferred income taxes, net | $ | 4,241 |
| | $ | 3,857 |
| $ | 2,760 |
| | $ | 4,654 |
|
On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentationThe implementation of deferred income taxes. The new guidance resulted in a reclassification from prepaid expenses of $20 million and accrued income tax of $2 million to non-currentTax Reform Legislation significantly reduced accumulated deferred income taxes, in the Company’s December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information.
The application ofpartially offset by bonus depreciation provisions in current tax law hasthe 2015 Protecting Americans from Tax Hikes Act. Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014.tax-related regulatory liabilities.
NOTES (continued)
Alabama Power Company 2015 Annual Report
At December 31, 2015,2017, the tax-related regulatory assets to be recovered from customers were $523$240 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.
At December 31, 2015,2017, the tax-related regulatory liabilities to be credited to customers were $70 million.$2.1 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $7 million in 2017 and $8 million annually in 2015, 20142016 and 2013.2015. At December 31, 2015, all ITCs available2017, the Company had federal ITC carryforwards which are expected to reduceresult in $9 million of federal income taxes payabletax benefits. The federal ITC carryforwards begin expiring in 2038 but are expected to be fully utilized by 2027. The ultimate outcome of these matters cannot be determined at this time.
Tax Credit Carryforwards
The Company had beenstate credit carryforwards for the state of Alabama of approximately $4 million, which begin expiring in 2023 but are expected to be fully utilized.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0% | | 35.0% | | 35.0% | 35.0% | | 35.0% | | 35.0% |
State income tax, net of federal deduction | 3.8 | | 4.4 | | 4.0 | 4.4 | | 4.2 | | 3.8 |
Non-deductible book depreciation | 1.2 | | 1.1 | | 1.0 | 0.9 | | 1.0 | | 1.2 |
Differences in prior years' deferred and current tax rates | (0.1) | | (0.1) | | (0.1) | |
AFUDC equity | (1.6) | | (1.3) | | (0.9) | (1.0) | | (0.7) | | (1.6) |
Tax Reform Legislation | | 0.3 | | — | | — |
Other | 0.1 | | (0.1) | | (0.1) | — | | (0.7) | | — |
Effective income tax rate | 38.4% | | 39.0% | | 38.9% | 39.6% | | 38.8% | | 38.4% |
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Unrecognized Tax Benefits
The Company has no material unrecognized tax benefits for 2015 or 2014.the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and the Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Long-Term Debt Payable to an Affiliated Trust
The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million outstanding as of December 31, 20152017 and 2014,2016, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At December 31, 20152017 and 2014,2016, trust preferred securities of $200 million were outstanding. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities.
Securities Due Within One Year
At December 31, 2015,2017, the Company had $200 million of senior notes and pollution control revenue bondsno securities due within one year. At December 31, 2014,2016, the Company had $454$561 million of senior notes and pollution control revenue bonds due within one year.
Maturities through 20202022 applicable to total long-term debt are as follows: $200 million in 2016; $5622019; $250 million in 2017; $2012020; $310 million in 2019;2021; and $251$750 million in 2020.2022. There are no material scheduled maturities in 2018.
Bank Term Loans
II-191At both December 31, 2017 and 2016, the Company had $45 million of outstanding bank term loan agreements, which are reflected in the statements of capitalization as long-term debt.
NOTES (continued)
Alabama Power Company 20152017 Annual Report
These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. At December 31, 2017, the Company was in compliance with its debt limits.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The Company incurred no obligations related to the issuance of pollution control revenue bonds in 2015.2017.
In April 2015, Alabama Power purchased and held $80August 2017, the Company repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015..
The amountCompany had $1.06 billion and $1.10 billion of tax-exempt pollution control revenue bondsbond obligations outstanding at December 31, 20152017 and 2014 was $1.1 billion and $1.2 billion, respectively.2016, respectively, including pollution control revenue bonds classified as due within one year.
Senior Notes
In March 2015,2017, the Company issued $550 million aggregate principal amount of Series 2015A 3.750%2017A 2.45% Senior Notes due March 1, 2045.30, 2022. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.650% Senior Notes due March 15, 2035repay the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In April 2015,November 2017, the Company issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250$550 million aggregate principal amount of its Series 2015B 2.800%2017B 3.70% Senior Notes due AprilDecember 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used in May 2015 to redeem certain classes of the Company's preferred and preference stock plus accrued and unpaid dividends to the redemption date, and the remaining net2047. The proceeds were used for general corporate purposes, including the Company's continuous construction program. See "Redeemable Preferred Stock" herein for additional information.program.
At December 31, 20152017 and 2014,2016, the Company had $5.6$6.4 billion and $5.3$5.8 billion of senior notes outstanding, respectively. As ofrespectively, including senior notes classified as due within one year. At December 31, 2015,2017 and 2016, the Company did not have any outstanding secured debt.
Subsequent to December 31, 2015, the Company issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including the Company's continuous construction program.
Redeemable Preferred and Preference Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock outstanding. The Company also has authorized andpreference stock, none of which is outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution.
NOTES (continued)
Alabama Power Company 20152017 Annual Report
The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are subject to redemption at a price equal to the stated capital. All series of the Company's preferred stock currently are subject to redemption at the option of the Company. The Class A preferred stock is subject to redemption on or after October 1, 2022, or following the occurrence of a rating agency event. Information for each outstanding series is in the table below:
| | Preferred/Preference Stock | Par Value/Stated Capital Per Share |
| Shares Outstanding |
| Redemption Price Per Share | Par Value/Stated Capital Per Share |
| Shares Outstanding |
| Redemption Price Per Share |
4.92% Preferred Stock | $100 |
| 80,000 |
|
| $103.23 | $100 |
| 80,000 |
|
| $103.23 |
4.72% Preferred Stock | $100 |
| 50,000 |
|
| $102.18 | $100 |
| 50,000 |
|
| $102.18 |
4.64% Preferred Stock | $100 |
| 60,000 |
|
| $103.14 | $100 |
| 60,000 |
|
| $103.14 |
4.60% Preferred Stock | $100 |
| 100,000 |
|
| $104.20 | $100 |
| 100,000 |
|
| $104.20 |
4.52% Preferred Stock | $100 |
| 50,000 |
|
| $102.93 | $100 |
| 50,000 |
|
| $102.93 |
4.20% Preferred Stock | $100 |
| 135,115 |
|
| $105.00 | $100 |
| 135,115 |
|
| $105.00 |
5.83% Class A Preferred Stock | $25 |
| 1,520,000 |
|
| Stated Capital | |
6.450% Preference Stock | $25 |
| 6,000,000 |
|
| * | |
6.500% Preference Stock | $25 |
| 2,000,000 |
|
| * | |
5.00% Class A Preferred Stock | | $25 |
| 10,000,000 |
|
| Stated Capital(*) |
| |
*(*) | Prior to 10/01/2017: Stated Value Plus Make-Whole Premium;October 1, 2022: $25.50; on or after 10/01/2017:October 1, 2022: Stated Capital |
In May 2015,September 2017, the Company redeemed 6.48issued 10 million shares ($162250 million aggregate stated capital) of the Company's 5.20%5.00% Class A Preferred Stock, at a redemption price of $25 per share plus accrued and unpaid dividendsCumulative, Par Value $1 Per Share (Stated Capital 25 Per Share). The proceeds were used in October 2017 to the redemption date and 4.0redeem all 2 million shares ($10050 million aggregate stated capital) of the Company's 5.30% Class A Preferred6.50% Series Preference Stock, at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date. Additionally, the $5 million of issuance costs were transferred from redeemable preferred stock to common stockholder's equity upon redemption. Also during May 2015, the Company redeemed 6.06 million shares ($150 million aggregate stated capital) of the Company's 5.625%6.45% Series Preference Stock, at a redemption priceand 1.52 million shares ($38 million aggregate stated capital) of $25 per share plus accrued5.83% Class A Preferred Stock and unpaid dividends tofor other general corporate purposes, including the redemption date. Company's continuous construction program.
There were no changes for the yearsyear ended December 31, 2014 and 20132016 in redeemable preferred stock or preference stock of the Company.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Bank Credit Arrangements
At December 31, 20152017, committed credit arrangements with banks were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Expires | | | | | | Due Within One Year |
2016 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) |
$ | 40 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,340 |
| | $ | 1,340 |
| | $ | — |
| | $ | 40 |
|
As reflected in the table above, in August 2015, the Company amended and restated its multi-year credit arrangements, which, among other things, extended the maturity dates from 2018 to 2020. In September 2015, the Company entered into a new $500 million three-year credit arrangement which replaced a majority of the Company's bilateral credit arrangements. |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Expires | | | | | | Expires Within One Year |
2018 | | 2020 | | 2022 | | Total | | Unused | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) |
$ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
Most of the bank credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/104 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.
NOTES (continued)
Alabama Power Company 2015 Annual Report
Subject to applicable market conditions, the Company expects to renew or replace its bank credit agreements as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder.
Most of the Company's bank credit arrangements contain covenants that limit the Company's debt level to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 20152017, the Company was in compliance with the debt limit covenants.
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper program.programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $810$854 million as of December 31, 2015.2017. In addition, at December 31, 2015,2017, the Company had $80$120 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
The Company borrows through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. The Company may also make short-term borrowings through various other arrangements with
NOTES (continued)
Alabama Power Company 2017 Annual Report
banks. At December 31, 2015 and 2014, there was no2017, the Company had $3 million in short-term debt outstanding.outstanding and none at December 31, 2016. At December 31, 2015,2017, the Company had regulatory approval to have outstanding up to $2.1$2.0 billion of short-term borrowings.
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2015, 2014,2017, 2016, and 2013,2015, the Company incurred fuel expense of $1.2 billion, $1.3 billion, $1.6 billion, and $1.6$1.3 billion, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
In addition, the Company has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases. Total capacity expense under PPAs accounted for as operating leases was $41 million, $42 million, and $38 million $37 million,for 2017, 2016, and $30 million for 2015, 2014, and 2013, respectively. Total estimated minimum long-term obligations at December 31, 20152017 were as follows:
| | | Operating Lease PPAs | Operating Lease PPAs |
| (in millions) | (in millions) |
2016 | $ | 39 |
| |
2017 | 40 |
| |
2018 | 41 |
| $ | 41 |
|
2019 | 43 |
| 43 |
|
2020 | 44 |
| 44 |
|
2021 and thereafter | 93 |
| |
2021 | | 46 |
|
2022 | | 47 |
|
2023 and thereafter | | — |
|
Total commitments | $ | 300 |
| $ | 221 |
|
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
The Company has entered into operating leases with Southern Linc and third parties for the use of cellular tower space. Substantially all of these agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years. The Company has entered into rental agreements for towers, coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense under these agreements was $25 million in 2017, $18 million in 2016, and $19 million in 2015, $18 million in 2014, and $21 million in 2013.2015. Of these amounts, $13$11 million, $14 million, and $18$13 million for 2015, 2014,2017, 2016, and 2013,2015, respectively, relate to the railcar leases and are recoverablewas recovered through the Company's Rate ECR. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.
NOTES (continued)
Alabama Power Company 20152017 Annual Report
through the Company's Rate ECR. As of December 31, 2015,2017, estimated minimum lease payments under operating leases were as follows:
| | | Minimum Lease Payments | Minimum Lease Payments(a) |
| Railcars | | Vehicles & Other | | Total | Affiliate Operating Leases(b) | | Railcars | | Vehicles & Other | | Total |
| (in millions) | | | (in millions) | | | | |
2016 | $ | 13 |
| | $ | 6 |
| | $ | 19 |
| |
2017 | 8 |
| | 5 |
| | 13 |
| |
2018 | 5 |
| | 4 |
| | 9 |
| $ | 8 |
| | $ | 7 |
| | $ | 6 |
| | $ | 21 |
|
2019 | 5 |
| | 4 |
| | 9 |
| 10 |
| | 7 |
| | 5 |
| | 22 |
|
2020 | 5 |
| | 4 |
| | 9 |
| 8 |
| | 7 |
| | 3 |
| | 18 |
|
2021 and thereafter | 13 |
| | — |
| | 13 |
| |
2021 | | 7 |
| | 6 |
| | 1 |
| | 14 |
|
2022 | | 5 |
| | 5 |
| | — |
| | 10 |
|
2023 and thereafter | | 16 |
| | 4 |
| | — |
| | 20 |
|
Total | $ | 49 |
| | $ | 23 |
| | $ | 72 |
| $ | 54 |
| | $ | 36 |
| | $ | 15 |
| | $ | 105 |
|
| |
(a) | Minimum lease payments have not been reduced by minimum sublease rentals of $3 million in the future. |
| |
(b) | Includes operating leases for cellular tower space. |
In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum obligations under these leases of $4 million in 2016 and $12 million in 2021 and thereafter.2023. There are no obligations under these leases in 2017, 2018, 2019, and 2020.through 2022. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations.
Guarantees
The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information.
8. STOCK COMPENSATION
Stock-Based Compensation
Stock-based compensation primarily in the form of Southern Company stock optionsperformance share units and performance sharerestricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2015,2017, there were 881793 current and former employees participating in the stock option, and performance share unit, programs.
Stock Options
Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualifiedand restricted stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units.
For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 2,027,298 shares and 1,319,038 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93, respectively.
NOTES (continued)
Alabama Power Company 2015 Annual Report
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $8 million, $21 million, and $11 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $3 million, $8 million, and $4 million for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, the aggregate intrinsic value for the options outstanding and options exercisable was $33 million and $26 million, respectively.unit programs.
Performance Share Units
From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period which equates to the requisite service period for accounting purposes.period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
The performance goal for allSouthern Company issues performance share units issued from 2010 through 2014 waswith performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For thesepeers, performance share units at the end of three years, active employees receive shareswith performance goals based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service duringcumulative earnings per share (EPS) over the performance period, priorand performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
NOTES (continued)
Alabama Power Company 2017 Annual Report
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. TheEmployees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee.retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, employees of the Company were granted performance share units of 214,709, 176,070,135,502, 249,065, and 141,355,214,709, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014,2017, 2016, and 2013,2015, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $46.42, $37.54,$49.07, $45.15, and $40.50,$46.42, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $47.78.$49.21, $48.86, and $47.78, respectively.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, total compensation cost for performance share units recognized in income was $13$9 million, $5$15 million, and $5$13 million, respectively, with the related tax benefit also recognized in income of $5$4 million, $2$6 million, and $2$5 million, respectively. The compensation cost and tax benefits related to the grant of Southern
NOTES (continued)
Alabama Power Company 2015 Annual Report
Company performance share units to the Company's employees areis recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015, there was $42017, $2 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 1921 months.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
For the year ended December 31, 2017, employees of the Company were granted 58,001 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.21.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $3 million with the related tax benefit also recognized in income of $1 million. As of December 31, 2017, total unrecognized compensation cost related to restricted stock units was immaterial.
Stock Options
In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
NOTES (continued)
Alabama Power Company 2017 Annual Report
The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017, all compensation cost related to stock option awards has been recognized.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $12 million, $21 million, and $8 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $5 million, $8 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017, the aggregate intrinsic value for the options outstanding and exercisable was $17 million.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $13.5$13.4 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375$450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $255 million per incident but not more than an aggregate of $38 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policyand policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years.exhausted. The Company purchases limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period.
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company as of December 31, 2017 under the NEIL policies would be $55 million.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
NOTES (continued)
Alabama Power Company 2017 Annual Report
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
NOTES (continued)
Alabama Power Company 2015 Annual Report
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
As of December 31, 2015,2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | — |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Nuclear decommissioning trusts:(*) | | | | | | | | | | | | | | | | | | |
Domestic equity | 359 |
| | 68 |
| | — |
| | — |
| | 427 |
| 442 |
| | 81 |
| | — |
| | — |
| | 523 |
|
Foreign equity | 47 |
| | 47 |
| | — |
| | — |
| | 94 |
| 62 |
| | 59 |
| | — |
| | — |
| | 121 |
|
U.S. Treasury and government agency securities | — |
| | 27 |
| | — |
| | — |
| | 27 |
| — |
| | 24 |
| | — |
| | — |
| | 24 |
|
Corporate bonds | 11 |
| | 135 |
| | — |
| | — |
| | 146 |
| 21 |
| | 160 |
| | — |
| | — |
| | 181 |
|
Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
| — |
| | 18 |
| | — |
| | — |
| | 18 |
|
Private equity | — |
| | — |
| | — |
| | 17 |
| | 17 |
| — |
| | — |
| | — |
| | 29 |
| | 29 |
|
Other | — |
| | 5 |
| | — |
| | — |
| | 5 |
| 6 |
| | — |
| | — |
| | — |
| | 6 |
|
Cash equivalents | 68 |
| | — |
| | — |
| | — |
| | 68 |
| 349 |
| | — |
| | — |
| | — |
| | 349 |
|
Total | $ | 485 |
| | $ | 301 |
| | $ | — |
| | $ | 17 |
| | $ | 803 |
| $ | 880 |
| | $ | 346 |
| | $ | — |
| | $ | 29 |
| | $ | 1,255 |
|
Liabilities: | | | | | | | | | | | | | | | | | | |
Interest rate derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
| |
Energy-related derivatives | — |
| | 55 |
| | — |
| | — |
| | 55 |
| $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
Total | $ | — |
| | $ | 70 |
| | $ | — |
| | $ | — |
| | $ | 70 |
| |
| |
(*) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. |
NOTES (continued)
Alabama Power Company 20152017 Annual Report
As of December 31, 20142016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | — |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 20 |
|
Nuclear decommissioning trusts:(*) |
|
| |
|
| |
|
| | | |
|
|
|
| |
|
| |
|
| | | |
|
|
Domestic equity | 403 |
| | 83 |
| | — |
| | — |
| | 486 |
| 385 |
| | 72 |
| | — |
| | — |
| | 457 |
|
Foreign equity | 34 |
| | 63 |
| | — |
| | — |
| | 97 |
| 48 |
| | 47 |
| | — |
| | — |
| | 95 |
|
U.S. Treasury and government agency securities | — |
| | 34 |
| | — |
| | — |
| | 34 |
| — |
| | 21 |
| | — |
| | — |
| | 21 |
|
Corporate bonds | — |
| | 111 |
| | — |
| | — |
| | 111 |
| 22 |
| | 146 |
| | — |
| | — |
| | 168 |
|
Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
| — |
| | 19 |
| | — |
| | — |
| | 19 |
|
Private equity | — |
| | — |
| | — |
| | 3 |
| | 3 |
| — |
| | — |
| | — |
| | 20 |
| | 20 |
|
Other | — |
| | 5 |
| | — |
| | — |
| | 5 |
| — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Cash equivalents | 162 |
| | — |
| | — |
| | — |
| | 162 |
| 262 |
| | — |
| | — |
| | — |
| | 262 |
|
Total | $ | 599 |
| | $ | 315 |
| | $ | — |
| | $ | 3 |
| | $ | 917 |
| $ | 717 |
| | $ | 335 |
| | $ | — |
| | $ | 20 |
| | $ | 1,072 |
|
Liabilities: | | | | | | | | | | | | | | | | | | |
Interest rate derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
| |
Energy-related derivatives | — |
| | 53 |
| | — |
| | — |
| | 53 |
| $ | — |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
Total | $ | — |
| | $ | 61 |
| | $ | — |
| | $ | — |
| | $ | 61 |
| |
| |
(*) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. |
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflectreflects the net present value of expected payments and receipts under the swap agreement based on the market’smarket's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. See Note 1 under "Nuclear Decommissioning" for additional information.
A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models,
NOTES (continued)
Alabama Power Company 2015 Annual Report
pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.
The
NOTES (continued)
Alabama Power Company early adopted ASU 2015-07 effective December 31, 2015. As required, disclosures in the paragraphs and table below are limited to only those investments in funds that are measured at net asset value as a practical expedient. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation.2017 Annual Report
As of December 31, 20152017 and 2014,2016, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) | | | | |
As of December 31, 2015 | $ | 17 |
| | $ | 28 |
| | Not Applicable | | Not Applicable |
As of December 31, 2014 | $ | 3 |
| | $ | 7 |
| | Not Applicable | | Not Applicable |
|
| | | | | | | | | | | |
| Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| (in millions) | | | | |
As of December 31, 2017 | $ | 29 |
| | $ | 21 |
| | Not Applicable | | Not Applicable |
As of December 31, 2016 | $ | 20 |
| | $ | 25 |
| | Not Applicable | | Not Applicable |
Private equity funds include a fund-of-funds that invests in high quality private equity funds across several market sectors, a fundfunds that investsinvest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations of these investments are expected to occur at various times over the next ten10 years.
As of December 31, 20152017 and 2014,2016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2015 | $ | 6,849 |
| | $ | 7,192 |
|
2014 | $ | 6,586 |
| | $ | 7,321 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 7,625 |
| | $ | 8,305 |
|
2016 | $ | 7,092 |
| | $ | 7,544 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.
11. DERIVATIVES
The Company is exposed to market risks, primarilyincluding commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
Energy-related derivative contracts are accounted for under one of two methods:
NOTES (continued)
Alabama Power Company 2015 Annual Report
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the energy cost recovery clause.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
NOTES (continued)
Alabama Power Company 2017 Annual Report
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 20152017, the net volume of energy-related derivative contracts for natural gas positions totaled 69 million mmBtu for the Company, together with the longest hedge date of 2020 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions andtransactions.
In addition to the longest date for derivatives not designated as hedges, were as follows:
|
| | | | |
Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
(in millions) | | | | |
50 | | 2018 | | — |
volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 5 million mmBtu.Interest Rate Derivatives
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings.
At December 31, 2015, the following2017, there were no interest rate derivative was outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2015 |
| (in millions) | | | | | | | | (in millions) |
Cash Flow Hedges of Forecasted Debt | | | | | | | | |
| $ | 200 |
| | 3-month LIBOR | | 2.93% | | October 2025 | | $ | (15 | ) |
derivatives outstanding.The estimated pre-tax losses related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 20162018 are $4$6 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035.
NOTES (continued)
Alabama Power Company 2015 Annual Report
Derivative Financial Statement Presentation and Amounts
At December 31, 2015 and 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | 1 |
| | $ | 1 |
| | Liabilities from risk management activities | $ | 40 |
| | $ | 32 |
|
| Other deferred charges and assets | — |
| | — |
| | Other deferred credits and liabilities | 15 |
| | 21 |
|
Total derivatives designated as hedging instruments for regulatory purposes | | $ | 1 |
| | $ | 1 |
| | | $ | 55 |
| | $ | 53 |
|
Derivatives designated as hedging instruments in cash flow hedges | | | | | | | | | |
Interest rate derivatives: | Other current assets | $ | — |
| | $ | — |
| | Liabilities from risk management activities | $ | 15 |
| | $ | 8 |
|
Total | | $ | 1 |
| | $ | 1 |
| | | $ | 70 |
| | $ | 61 |
|
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014.
The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of theseCompany enters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts relatedFair value amounts of derivative assets and liabilities on the balance sheets are presented net to energy-related derivative contracts at the extent that there are netting arrangements or similar agreements with the counterparties.
At December 31, 20152017 and 2014 are presented in2016, the following tables. Interest ratefair value of energy-related derivatives presented inwas reflected on the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below.balance sheets as follows:
|
| | | | | | | | | | | | | | | | |
Fair Value |
Assets | 2015 |
| | 2014 |
| | Liabilities | 2015 |
| | 2014 |
|
| (in millions) | | | (in millions) |
Energy-related derivatives presented in the Balance Sheet (a) | $ | 1 |
| | $ | 1 |
| | Energy-related derivatives presented in the Balance Sheet (a) | $ | 55 |
| | $ | 53 |
|
Gross amounts not offset in the Balance Sheet (b) | (1 | ) | | — |
| | Gross amounts not offset in the Balance Sheet (b) | (1 | ) | | — |
|
Net energy-related derivative assets | $ | — |
| | $ | 1 |
| | Net energy-related derivative liabilities | $ | 54 |
| | $ | 53 |
|
|
| | | | | | | | | | | | |
| 2017 | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 2 |
| $ | 6 |
| $ | 13 |
| $ | 5 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 4 |
| 7 |
| 4 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 4 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
Gross amounts recognized | $ | 4 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
Gross amounts offset | $ | (4 | ) | $ | (4 | ) | $ | (8 | ) | $ | (8 | ) |
Net amounts recognized in the Balance Sheets | $ | — |
| $ | 6 |
| $ | 12 |
| $ | 1 |
|
| |
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
II-202Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and 2016.
NOTES (continued)
Alabama Power Company 20152017 Annual Report
At December 31, 20152017 and 20142016, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instrumentsderivatives designated as regulatory hedging instruments and deferred were as follows:
| | | Unrealized Losses | | Unrealized Gains | Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (40 | ) | | $ | (32 | ) | | Other current liabilities | $ | 1 |
| | $ | 1 |
| Other regulatory assets, current | $ | (4 | ) | | $ | (1 | ) | | Other regulatory liabilities, current | $ | 1 |
| | $ | 8 |
|
| Other regulatory assets, deferred | (15 | ) | | (21 | ) | | Other regulatory liabilities, deferred | — |
| | — |
| Other regulatory assets, deferred | (3 | ) | | — |
| | Other regulatory liabilities, deferred | — |
| | 4 |
|
Total energy-related derivative gains (losses) | | $ | (55 | ) | | $ | (53 | ) | | $ | 1 |
| | $ | 1 |
| | $ | (7 | ) | | $ | (1 | ) | | $ | 1 |
| | $ | 12 |
|
For the years ended December 31, 20152017, 20142016, and 20132015, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows:
| | Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | Amount | | | Amount |
Derivative Category | 2015 |
| | 2014 |
| | 2013 |
| | Statements of Income Location | 2015 |
| | 2014 | | 2013 |
| 2017 | | 2016 | | 2015 | | Statements of Income Location | 2017 | | 2016 | | 2015 |
| (in millions) | | (in millions) | (in millions) | | (in millions) |
Interest rate derivatives | $ | (7 | ) | | $ | (8 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) | | $ | (3 | ) | $ | — |
| | $ | (3 | ) | | $ | (7 | ) | | Interest expense, net of amounts capitalized | $ | (6 | ) | | $ | (6 | ) | | $ | (3 | ) |
There was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2015, 2014, and 2013, theThe pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material.material for any year presented.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015, the Company's collateral posted with its derivative counterparties was not material.
At December 31, 20152017, the fair value of derivative liabilities with contingent features was $16$1 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-relatedcredit-risk related contingent features, at a rating below BBB- and/or Baa3, were $52$12 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017, the Company's collateral posted in these accounts was not material.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES (continued)
Alabama Power Company 20152017 Annual Report
12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preferred and Preference Stock |
| (in millions) |
March 2015 | $ | 1,401 |
| | $ | 346 |
| | $ | 169 |
|
June 2015 | 1,455 |
| | 398 |
| | 200 |
|
September 2015 | 1,695 |
| | 555 |
| | 295 |
|
December 2015 | 1,217 |
| | 264 |
| | 121 |
|
| | | | | |
March 2014 | $ | 1,508 |
| | $ | 381 |
| | $ | 187 |
|
June 2014 | 1,437 |
| | 357 |
| | 173 |
|
September 2014 | 1,669 |
| | 520 |
| | 282 |
|
December 2014 | 1,328 |
| | 267 |
| | 119 |
|
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preferred and Preference Stock |
| (in millions) |
March 2017 | $ | 1,382 |
| | $ | 376 |
| | $ | 174 |
|
June 2017 | 1,484 |
| | 454 |
| | 230 |
|
September 2017 | 1,740 |
| | 616 |
| | 325 |
|
December 2017 | 1,433 |
| | 268 |
| | 119 |
|
| | | | | |
March 2016 | $ | 1,331 |
| | $ | 333 |
| | $ | 156 |
|
June 2016 | 1,444 |
| | 430 |
| | 213 |
|
September 2016 | 1,785 |
| | 650 |
| | 351 |
|
December 2016 | 1,329 |
| | 252 |
| | 102 |
|
The Company's business is influenced by seasonal weather conditions.
SELECTED FINANCIAL AND OPERATING DATA 2011-20152013-2017
Alabama Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 5,768 |
| | $ | 5,942 |
| | $ | 5,618 |
| | $ | 5,520 |
| | $ | 5,702 |
| $ | 6,039 |
| | $ | 5,889 |
| | $ | 5,768 |
| | $ | 5,942 |
| | $ | 5,618 |
|
Net Income After Dividends on Preferred and Preference Stock (in millions) | $ | 785 |
| | $ | 761 |
| | $ | 712 |
| | $ | 704 |
| | $ | 708 |
| $ | 848 |
| | $ | 822 |
| | $ | 785 |
| | $ | 761 |
| | $ | 712 |
|
Cash Dividends on Common Stock (in millions) | $ | 571 |
| | $ | 550 |
| | $ | 644 |
| | $ | 684 |
| | $ | 774 |
| $ | 714 |
| | $ | 765 |
| | $ | 571 |
| | $ | 550 |
| | $ | 644 |
|
Return on Average Common Equity (percent) | 13.37 |
| | 13.52 |
| | 13.07 |
| | 13.10 |
| | 13.19 |
| 12.89 |
| | 13.34 |
| | 13.37 |
| | 13.52 |
| | 13.07 |
|
Total Assets (in millions)(a)(b) | $ | 21,721 |
| | $ | 20,493 |
| | $ | 19,185 |
| | $ | 18,647 |
| | $ | 18,397 |
| $ | 23,864 |
| | $ | 22,516 |
| | $ | 21,721 |
| | $ | 20,493 |
| | $ | 19,185 |
|
Gross Property Additions (in millions) | $ | 1,492 |
| | $ | 1,543 |
| | $ | 1,204 |
| | $ | 940 |
| | $ | 1,016 |
| $ | 1,949 |
| | $ | 1,338 |
| | $ | 1,492 |
| | $ | 1,543 |
| | $ | 1,204 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 5,992 |
| | $ | 5,752 |
| | $ | 5,502 |
| | $ | 5,398 |
| | $ | 5,342 |
| $ | 6,829 |
| | $ | 6,323 |
| | $ | 5,992 |
| | $ | 5,752 |
| | $ | 5,502 |
|
Preference stock | 196 |
| | 343 |
| | 343 |
| | 343 |
| | 343 |
| — |
| | 196 |
| | 196 |
| | 343 |
| | 343 |
|
Redeemable preferred stock | 85 |
| | 342 |
| | 342 |
| | 342 |
| | 342 |
| 291 |
| | 85 |
| | 85 |
| | 342 |
| | 342 |
|
Long-term debt(a) | 6,654 |
| | 6,137 |
| | 6,195 |
| | 5,890 |
| | 5,586 |
| 7,628 |
| | 6,535 |
| | 6,654 |
| | 6,137 |
| | 6,195 |
|
Total (excluding amounts due within one year) | $ | 12,927 |
| | $ | 12,574 |
| | $ | 12,382 |
| | $ | 11,973 |
| | $ | 11,613 |
| $ | 14,748 |
| | $ | 13,139 |
| | $ | 12,927 |
| | $ | 12,574 |
| | $ | 12,382 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 46.4 |
| | 45.8 |
| | 44.4 |
| | 45.1 |
| | 46.0 |
| 46.3 |
| | 48.1 |
| | 46.4 |
| | 45.8 |
| | 44.4 |
|
Preference stock | 1.5 |
| | 2.7 |
| | 2.8 |
| | 2.9 |
| | 3.0 |
| — |
| | 1.5 |
| | 1.5 |
| | 2.7 |
| | 2.8 |
|
Redeemable preferred stock | 0.7 |
| | 2.7 |
| | 2.7 |
| | 2.9 |
| | 2.9 |
| 2.0 |
| | 0.7 |
| | 0.7 |
| | 2.7 |
| | 2.7 |
|
Long-term debt(a) | 51.4 |
| | 48.8 |
| | 50.1 |
| | 49.1 |
| | 48.1 |
| 51.7 |
| | 49.7 |
| | 51.4 |
| | 48.8 |
| | 50.1 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Customers (year-end): | | | | | | | | | | | | | | | | | | |
Residential | 1,253,875 |
| | 1,247,061 |
| | 1,241,998 |
| | 1,237,730 |
| | 1,231,574 |
| 1,268,271 |
| | 1,262,752 |
| | 1,253,875 |
| | 1,247,061 |
| | 1,241,998 |
|
Commercial | 197,920 |
| | 197,082 |
| | 196,209 |
| | 196,177 |
| | 196,270 |
| 199,840 |
| | 199,146 |
| | 197,920 |
| | 197,082 |
| | 196,209 |
|
Industrial | 6,056 |
| | 6,032 |
| | 5,851 |
| | 5,839 |
| | 5,844 |
| 6,171 |
| | 6,090 |
| | 6,056 |
| | 6,032 |
| | 5,851 |
|
Other | 757 |
| | 753 |
| | 751 |
| | 748 |
| | 746 |
| 766 |
| | 762 |
| | 757 |
| | 753 |
| | 751 |
|
Total | 1,458,608 |
| | 1,450,928 |
| | 1,444,809 |
| | 1,440,494 |
| | 1,434,434 |
| 1,475,048 |
| | 1,468,750 |
| | 1,458,608 |
| | 1,450,928 |
| | 1,444,809 |
|
Employees (year-end) | 6,986 |
| | 6,935 |
| | 6,896 |
| | 6,778 |
| | 6,632 |
| 6,613 |
| | 6,805 |
| | 6,986 |
| | 6,935 |
| | 6,896 |
|
|
| |
(a) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $40 million $38 million, $39 million, and $47$38 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b) | A reclassification of deferred tax assets from Total Assets of $20 million $27 million, $27 million, and $33$27 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-17. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
SELECTED FINANCIAL AND OPERATING DATA 2013-2017 (continued)
Alabama Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 2,302 |
| | $ | 2,322 |
| | $ | 2,207 |
| | $ | 2,209 |
| | $ | 2,079 |
|
Commercial | 1,649 |
| | 1,627 |
| | 1,564 |
| | 1,533 |
| | 1,477 |
|
Industrial | 1,477 |
| | 1,416 |
| | 1,436 |
| | 1,480 |
| | 1,369 |
|
Other | 30 |
| | (43 | ) | | 27 |
| | 27 |
| | 27 |
|
Total retail | 5,458 |
| | 5,322 |
| | 5,234 |
| | 5,249 |
| | 4,952 |
|
Wholesale — non-affiliates | 276 |
| | 283 |
| | 241 |
| | 281 |
| | 248 |
|
Wholesale — affiliates | 97 |
| | 69 |
| | 84 |
| | 189 |
| | 212 |
|
Total revenues from sales of electricity | 5,831 |
| | 5,674 |
| | 5,559 |
| | 5,719 |
| | 5,412 |
|
Other revenues | 208 |
| | 215 |
| | 209 |
| | 223 |
| | 206 |
|
Total | $ | 6,039 |
| | $ | 5,889 |
| | $ | 5,768 |
| | $ | 5,942 |
| | $ | 5,618 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 17,219 |
| | 18,343 |
| | 18,082 |
| | 18,726 |
| | 17,920 |
|
Commercial | 13,606 |
| | 14,091 |
| | 14,102 |
| | 14,118 |
| | 13,892 |
|
Industrial | 22,687 |
| | 22,310 |
| | 23,380 |
| | 23,799 |
| | 22,904 |
|
Other | 198 |
| | 208 |
| | 201 |
| | 211 |
| | 211 |
|
Total retail | 53,710 |
| | 54,952 |
| | 55,765 |
| | 56,854 |
| | 54,927 |
|
Wholesale — non-affiliates | 5,415 |
| | 5,744 |
| | 3,567 |
| | 3,588 |
| | 3,711 |
|
Wholesale — affiliates | 4,166 |
| | 3,177 |
| | 4,515 |
| | 6,713 |
| | 7,672 |
|
Total | 63,291 |
| | 63,873 |
| | 63,847 |
| | 67,155 |
| | 66,310 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 13.37 |
| | 12.66 |
| | 12.21 |
| | 11.80 |
| | 11.60 |
|
Commercial | 12.12 |
| | 11.55 |
| | 11.09 |
| | 10.86 |
| | 10.63 |
|
Industrial | 6.51 |
| | 6.35 |
| | 6.14 |
| | 6.22 |
| | 5.98 |
|
Total retail | 10.16 |
| | 9.68 |
| | 9.39 |
| | 9.23 |
| | 9.02 |
|
Wholesale | 3.89 |
| | 3.95 |
| | 4.02 |
| | 4.56 |
| | 4.04 |
|
Total sales | 9.21 |
| | 8.88 |
| | 8.71 |
| | 8.52 |
| | 8.16 |
|
Residential Average Annual Kilowatt-Hour Use Per Customer | 13,601 |
| | 14,568 |
| | 14,454 |
| | 15,051 |
| | 14,451 |
|
Residential Average Annual Revenue Per Customer | $ | 1,819 |
| | $ | 1,844 |
| | $ | 1,764 |
| | $ | 1,775 |
| | $ | 1,676 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts) | 11,797 |
| | 11,797 |
| | 11,797 |
| | 12,222 |
| | 12,222 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 10,513 |
| | 10,282 |
| | 12,162 |
| | 11,761 |
| | 9,347 |
|
Summer | 10,711 |
| | 10,932 |
| | 11,292 |
| | 11,054 |
| | 10,692 |
|
Annual Load Factor (percent) | 63.5 |
| | 63.5 |
| | 58.4 |
| | 61.4 |
| | 64.9 |
|
Plant Availability (percent): | | | | | | | | | |
Fossil-steam | 82.8 |
| | 83.0 |
| | 81.5 |
| | 82.5 |
| | 87.3 |
|
Nuclear | 97.6 |
| | 88.0 |
| | 92.1 |
| | 93.3 |
| | 90.7 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 44.8 |
| | 47.1 |
| | 49.1 |
| | 49.0 |
| | 50.0 |
|
Nuclear | 22.2 |
| | 20.3 |
| | 21.3 |
| | 20.7 |
| | 20.3 |
|
Hydro | 5.4 |
| | 4.8 |
| | 5.6 |
| | 5.5 |
| | 8.1 |
|
Gas | 18.1 |
| | 17.1 |
| | 14.6 |
| | 15.4 |
| | 15.7 |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 4.6 |
| | 4.8 |
| | 4.4 |
| | 3.6 |
| | 2.9 |
|
From affiliates | 4.9 |
| | 5.9 |
| | 5.0 |
| | 5.8 |
| | 3.0 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
SELECTED FINANCIAL AND OPERATING DATA 2011-2015 (continued)
Alabama Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 2,207 |
| | $ | 2,209 |
| | $ | 2,079 |
| | $ | 2,068 |
| | $ | 2,144 |
|
Commercial | 1,564 |
| | 1,533 |
| | 1,477 |
| | 1,491 |
| | 1,495 |
|
Industrial | 1,436 |
| | 1,480 |
| | 1,369 |
| | 1,346 |
| | 1,306 |
|
Other | 27 |
| | 27 |
| | 27 |
| | 28 |
| | 27 |
|
Total retail | 5,234 |
| | 5,249 |
| | 4,952 |
| | 4,933 |
| | 4,972 |
|
Wholesale — non-affiliates | 241 |
| | 281 |
| | 248 |
| | 277 |
| | 287 |
|
Wholesale — affiliates | 84 |
| | 189 |
| | 212 |
| | 111 |
| | 244 |
|
Total revenues from sales of electricity | 5,559 |
| | 5,719 |
| | 5,412 |
| | 5,321 |
| | 5,503 |
|
Other revenues | 209 |
| | 223 |
| | 206 |
| | 199 |
| | 199 |
|
Total | $ | 5,768 |
| | $ | 5,942 |
| | $ | 5,618 |
| | $ | 5,520 |
| | $ | 5,702 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 18,082 |
| | 18,726 |
| | 17,920 |
| | 17,612 |
| | 18,650 |
|
Commercial | 14,102 |
| | 14,118 |
| | 13,892 |
| | 13,963 |
| | 14,173 |
|
Industrial | 23,380 |
| | 23,799 |
| | 22,904 |
| | 22,158 |
| | 21,666 |
|
Other | 201 |
| | 211 |
| | 211 |
| | 214 |
| | 214 |
|
Total retail | 55,765 |
| | 56,854 |
| | 54,927 |
| | 53,947 |
| | 54,703 |
|
Wholesale — non-affiliates | 3,567 |
| | 3,588 |
| | 3,711 |
| | 4,196 |
| | 4,330 |
|
Wholesale — affiliates | 4,515 |
| | 6,713 |
| | 7,672 |
| | 4,279 |
| | 7,211 |
|
Total | 63,847 |
| | 67,155 |
| | 66,310 |
| | 62,422 |
| | 66,244 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.21 |
| | 11.80 |
| | 11.60 |
| | 11.74 |
| | 11.50 |
|
Commercial | 11.09 |
| | 10.86 |
| | 10.63 |
| | 10.68 |
| | 10.55 |
|
Industrial | 6.14 |
| | 6.22 |
| | 5.98 |
| | 6.07 |
| | 6.03 |
|
Total retail | 9.39 |
| | 9.23 |
| | 9.02 |
| | 9.14 |
| | 9.09 |
|
Wholesale | 4.02 |
| | 4.56 |
| | 4.04 |
| | 4.58 |
| | 4.60 |
|
Total sales | 8.71 |
| | 8.52 |
| | 8.16 |
| | 8.52 |
| | 8.31 |
|
Residential Average Annual Kilowatt-Hour Use Per Customer | 14,454 |
| | 15,051 |
| | 14,451 |
| | 14,252 |
| | 15,138 |
|
Residential Average Annual Revenue Per Customer | $ | 1,764 |
| | $ | 1,775 |
| | $ | 1,676 |
| | $ | 1,674 |
| | $ | 1,740 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts) | 11,797 |
| | 12,222 |
| | 12,222 |
| | 12,222 |
| | 12,222 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 12,162 |
| | 11,761 |
| | 9,347 |
| | 10,285 |
| | 11,553 |
|
Summer | 11,292 |
| | 11,054 |
| | 10,692 |
| | 11,096 |
| | 11,500 |
|
Annual Load Factor (percent) | 58.4 |
| | 61.4 |
| | 64.9 |
| | 61.3 |
| | 60.6 |
|
Plant Availability (percent)*: | | | | | | | | | |
Fossil-steam | 81.5 |
| | 82.5 |
| | 87.3 |
| | 88.6 |
| | 88.7 |
|
Nuclear | 92.1 |
| | 93.3 |
| | 90.7 |
| | 94.5 |
| | 94.7 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 49.1 |
| | 49.0 |
| | 50.0 |
| | 48.2 |
| | 52.5 |
|
Nuclear | 21.3 |
| | 20.7 |
| | 20.3 |
| | 22.6 |
| | 20.8 |
|
Hydro | 5.6 |
| | 5.5 |
| | 8.1 |
| | 4.1 |
| | 4.6 |
|
Gas | 14.6 |
| | 15.4 |
| | 15.7 |
| | 16.8 |
| | 15.3 |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 4.4 |
| | 3.6 |
| | 2.9 |
| | 2.0 |
| | 0.9 |
|
From affiliates | 5.0 |
| | 5.8 |
| | 3.0 |
| | 6.3 |
| | 5.9 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
|
| |
* | Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
GEORGIA POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Georgia Power Company 20152017 Annual Report
The management of Georgia Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2015.2017.
/s/ W. Paul Bowers
W. Paul Bowers
Chairman, President, and Chief Executive Officer
/s/ W. Ron HinsonXia Liu
W. Ron HinsonXia Liu
Executive Vice President, Chief Financial Officer, Treasurer, and Corporate SecretaryTreasurer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of
Georgia Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Georgia Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014, and2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2015. 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-270 to II-321) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements (pages II-239 to II-287) present fairly, in all material respects, the financial position of Georgia Power Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
2013 ARP | Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019 |
AFUDC | Allowance for funds used during construction |
Alabama Power | Alabama Power Company |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
Bechtel | Bechtel Power Corporation |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
Contractor Settlement Agreement | The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement |
CWIP | Construction work in progress |
DOE | U.S. Department of Energy |
Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 |
EPA | U.S. Environmental Protection Agency |
EPC Contractor | Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
FFB | Federal Financing Bank |
GAAP | U.S. generally accepted accounting principles |
Gulf Power | Gulf Power Company |
Interim Assessment Agreement | Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
Loan Guarantee Agreement | Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4 |
LTSA | Long-term service agreement |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
NCCR | Nuclear Construction Cost Recovery |
NOX | Nitrogen oxide |
NRC | U.S. Nuclear Regulatory Commission |
OCI | Other comprehensive income |
DEFINITIONS
(continued)
Plant Vogtle Units 3 and 4 |
| Two new nuclear generating units under construction at Plant Vogtle |
Term | Meaning |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company(excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreement |
PSC | Public Service Commission |
PTC | Production tax credit |
ROE | Return on equity |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SEGCO | Southern Electric Generating Company |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
Toshiba | Toshiba Corporation, parent company of Westinghouse |
Toshiba Guarantee | Certain payment obligations of the EPC Contractor guaranteed by Toshiba |
traditional electric operating companies | Alabama Power, Georgia Power Company, Gulf Power, and Mississippi Power |
VCM | Vogtle Construction Monitoring |
Vogtle 3 and 4 Agreement | Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 |
Vogtle Owners | Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners |
Vogtle Services Agreement | The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear |
Westinghouse | Westinghouse Electric Company LLC |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power Company 20152017 Annual Report
OVERVIEW
Business Activities
Georgia Power Company (the Company) operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and fuel. In addition, construction continues on Plant Vogtle Units 3 and 4. The Company will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. On December 31, 2015, the Company and the other parties to the commercial litigation related to the construction of Plant Vogtle Units 3 and 4 entered into a settlement agreement resulting in the dismissal of the litigation.restoration following major storms. The Company has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. See Note 3 to the financial statements under "Retail Regulatory Matters – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
In accordance with the 2013 ARP approved by the Georgia PSC, the Company increased base rates approximately $110 million, $136 million, and $140 million effective January 1, 2014, 2015, and 2016, respectively. The Company is required to file its nexta base rate case with the Georgia PSC by July 1, 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information.
Key Performance Indicators2019.
The Company continues to focus on several key performance indicators, including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock.income. The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance, which the Company achieved during 2015.performance.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil/hydro plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The Company's 2015 Peak Season EFOR of 1.21% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages, with performance targets set based on historical performance. The Company's 2015 performance was below the target for these transmission and distribution reliability measures primarily due to the level of storm activity in the service territory during the year.
The Company uses net income after dividends on preferred and preference stock as the primary measure of the Company's financial performance. See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, the Company filed its seventeenth VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved the Company's recommendation to continue construction.
The Company expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. The Company's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement) and certain refunds to customers ordered by the Georgia PSC (Customer Refunds)). The Company's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Earnings
The Company's 20152017 net income after dividends on preferred and preference stock was $1.4 billion, representing a $84 million, or 6.3%, increase over the previous year. The increase was due primarily to lower non-fuel operations and maintenance expenses, primarily as a result of cost containment and modernization initiatives, partially offset by lower revenues resulting from milder weather and lower customer usage as compared to 2016.
The Company's 2016 net income after dividends on preferred and preference stock was $1.3 billion, representing a $35$70 million, or 2.9%5.6%, increase over the previous year. The increase was due primarily to an increase in base retail revenues effective January 1, 2015, as authorized by the Georgia PSC, and lower non-fuel operations and maintenance expenses, partially offset by the correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. See Note 1 to the financial statements under "General" for additional information.
The Company's 2014 net income after dividends on preferred and preference stock was $1.2 billion, representing a $51 million, or 4.3%, increase over the previous year. The increase was due primarily to an increase in base retail revenues effective January 1, 2014, as authorized under the 2013 ARP, and colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, partially offset by higher non-fuel operations and maintenance expenses.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
2016, as authorized by the Georgia PSC, the 2015 correction of a customer billing error, and higher retail revenues in the third quarter 2016 due to warmer weather as compared to the corresponding period in 2015, partially offset by an expected refund to retail customers as a result of the Company's retail ROE exceeding the retail ROE range allowed under the 2013 ARP during 2016. Higher non-fuel operating expenses also partially offset the revenue increase.
See Note 1 to the financial statements under "General" and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information related to the 2015 error correction and the refund to retail customers, respectively.
RESULTS OF OPERATIONS
A condensed income statement for the Company follows:
| | | Amount | | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Operating revenues | $ | 8,326 |
| | $ | (662 | ) | | $ | 714 |
| $ | 8,310 |
| | $ | (73 | ) | | $ | 57 |
|
Fuel | 2,033 |
| | (514 | ) | | 240 |
| 1,671 |
| | (136 | ) | | (226 | ) |
Purchased power | 864 |
| | (124 | ) | | 104 |
| 1,038 |
| | 159 |
| | 15 |
|
Other operations and maintenance | 1,844 |
| | (58 | ) | | 248 |
| 1,653 |
| | (307 | ) | | 116 |
|
Depreciation and amortization | 846 |
| | — |
| | 39 |
| 895 |
| | 40 |
| | 9 |
|
Taxes other than income taxes | 391 |
| | (18 | ) | | 27 |
| 409 |
| | 4 |
| | 14 |
|
Total operating expenses | 5,978 |
| | (714 | ) | | 658 |
| 5,666 |
| | (240 | ) | | (72 | ) |
Operating income | 2,348 |
| | 52 |
| | 56 |
| 2,644 |
| | 167 |
| | 129 |
|
Interest expense, net of amounts capitalized | 363 |
| | 15 |
| | (13 | ) | 419 |
| | 31 |
| | 25 |
|
Other income (expense), net | 61 |
| | 38 |
| | (12 | ) | 33 |
| | (5 | ) | | (23 | ) |
Income taxes | 769 |
| | 40 |
| | 6 |
| 830 |
| | 50 |
| | 11 |
|
Net income | 1,277 |
| | 35 |
| | 51 |
| 1,428 |
| | 81 |
| | 70 |
|
Dividends on preferred and preference stock | 17 |
| | — |
| | — |
| 14 |
| | (3 | ) | | — |
|
Net income after dividends on preferred and preference stock | $ | 1,260 |
| | $ | 35 |
| | $ | 51 |
| $ | 1,414 |
| | $ | 84 |
| | $ | 70 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
Operating Revenues
Operating revenues for 20152017 were $8.3 billion, reflecting a $662$73 million decrease from 2014.2016. Details of operating revenues were as follows:
| | | Amount | Amount |
| 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Retail — prior year | $ | 8,240 |
| | $ | 7,620 |
| $ | 7,772 |
| | $ | 7,727 |
|
Estimated change resulting from — | | | | | | |
Rates and pricing | 88 |
| | 183 |
| 114 |
| | 154 |
|
Sales growth | 63 |
| | 21 |
| |
Sales decline | | (33 | ) | | (10 | ) |
Weather | (19 | ) | | 139 |
| (166 | ) | | 113 |
|
Fuel cost recovery | (645 | ) | | 277 |
| 51 |
| | (212 | ) |
Retail — current year | 7,727 |
| | 8,240 |
| 7,738 |
| | 7,772 |
|
Wholesale revenues — | | | | | | |
Non-affiliates | 215 |
| | 335 |
| 163 |
| | 175 |
|
Affiliates | 20 |
| | 42 |
| 26 |
| | 42 |
|
Total wholesale revenues | 235 |
| | 377 |
| 189 |
| | 217 |
|
Other operating revenues | 364 |
| | 371 |
| 383 |
| | 394 |
|
Total operating revenues | $ | 8,326 |
| | $ | 8,988 |
| $ | 8,310 |
| | $ | 8,383 |
|
Percent change | (7.4 | )% | | 8.6 | % | (0.9 | )% | | 0.7 | % |
Retail base revenues of $5.3$7.7 billion in 2015 increased $1332017 decreased $34 million, or 2.6%0.4%, compared to 2014.2016. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to base tariff increases effective January 1, 2015, as approved by the Georgia PSCan increase in accordance with the 2013 ARP, and increases in collections for financing costsrevenues related to the constructionrecovery of Plant Vogtle Units 3 and 4 throughconstruction financing costs under the NCCR tariff, partially offset by the correctiontariff.
Retail revenues of an
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. In 2015, residential base revenues$7.8 billion in 2016 increased $104$45 million, or 4.5%, commercial base revenues increased $70 million, or 3.4%, and industrial base revenues decreased $41 million, or 5.6%0.6%, compared to 2014.
Retail base revenues of $5.2 billion in 2014 increased $343 million, or 7.1%, compared to 2013.2015. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to increases in base tariff increases effective January 1, 2014, astariffs approved by the Georgia PSC in accordance withunder the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, all effective January 1, 2016, and the 2015 correction of a customer billing error. The increase was partially offset by an adjustment for an expected refund to retail customers as well as higher contributions from variable demand-driven pricing from commercial and industrial customers. In 2014, residential base revenues increased $163 million, or 7.6%, commercial base revenues increased $108 million, or 5.5%, and industrial base revenues increased $74 million, or 11.1%, compared to 2013.a result of the Company's retail ROE exceeding the retail ROE range allowed under the 2013 ARP during 2016.
See Note 1 to the financial statements under "General" for additional information on the customer billing error correction and Note 3 to the financial statements under "Retail Regulatory Matters – Rate Plans" and " – Nuclear Construction" for additional information on the rate changes. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growthdecline and weather.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Wholesale revenues from power sales to non-affiliated utilities were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Capacity and other | $ | 108 |
| | $ | 164 |
| | $ | 174 |
| $ | 67 |
| | $ | 72 |
| | $ | 108 |
|
Energy | 107 |
| | 171 |
| | 107 |
| 96 |
| | 103 |
| | 107 |
|
Total non-affiliated | $ | 215 |
| | $ | 335 |
| | $ | 281 |
| $ | 163 |
| | $ | 175 |
| | $ | 215 |
|
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost of energy.
Wholesale revenues from non-affiliated sales decreased $120$12 million, or 35.8%6.9%, in 20152017 as compared to 20142016 and increased $54decreased $40 million, or 19.2%18.6%, in 20142016 as compared to 2013.2015. The decrease in 20152017 was related to decreases of $64$5 million in energycapacity revenues and $56$7 million in capacityenergy revenues. The decrease in energy revenues2016 was primarily duerelated to lower natural gas prices. The decreasedecreases of $36 million in capacity revenues reflectsand $4 million in energy revenues. The decreases in capacity revenues reflect the expiration of wholesale contracts in December 2014the first and second quarters of 2016. The decrease in capacity revenues in 2016 also reflects the retirement of 14 coal-fired generating units since March 31, 2015 as a result of the Company's environmental compliance strategy. The increasedecrease in 2014energy revenues in 2017 was primarily due to increasedlower demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the effects of the expired contracts. The decrease in energy revenues in 2016 was primarily due to lower cost of Company-owned generation compared to the market cost of available energy.fuel prices. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations – Air Quality" and – "Retail Regulatory Matters – Integrated Resource Plan" herein for additional information regarding the Company's environmental compliance strategy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. In 2015,2017, wholesale revenues from sales to affiliates decreased $22$16 million as compared to 20142016 due to lower natural gas prices and a 50.6%42.8% decrease in KWH sales due toas a result of the higher cost of Company-owned generation compared to thelower market cost of available energy.energy compared to the cost of Company-owned generation. In 2014,2016, wholesale revenues from sales to affiliates increased $22 million as compared to 20132015 due to colder weathera 153.5% increase in the first quarter 2014 and warmer weather in the second and third quarters 2014KWH sales as compared to the corresponding periods in 2013 anda result of the lower cost of Company-owned generation.generation compared to the market cost of available energy, partially offset by lower coal and natural gas prices.
Other operating revenues decreased $7$11 million, or 1.9%2.8%, in 20152017 from the prior year primarily due to a $16$15 million decrease in open access transmission servicetariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a contract that expired$14 million adjustment in December 2014,2016 for customer temporary facilities services revenues, partially offset by an $11a $13 million increase in outdoor lighting sales revenues. due to increased sales in new and replacement markets, primarily attributable to LED conversions.
Other operating revenues increased $18$30 million, or 5.1%8.2%, in 20142016 from the prior year
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
primarily due to $7a $14 million in transmission service revenues, $5 million of solar application feeincrease related to customer temporary facilities services revenues and $5a $12 million increase in outdoor lighting revenues.revenues due to increased sales in new and replacement markets, primarily attributable to LED conversions.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 20152017 and the percent change from the prior year were as follows:
| | | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2015 | | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in billions) | | | | | | | | | (in billions) | | | | | | | | |
Residential | 26.7 |
| | (1.8 | )% | | 6.5 | % | | 1.0 | % | | 0.5 | % | 26.1 |
| | (5.2 | )% | | 3.5 | % | | (0.2 | )% | | 1.0 | % |
Commercial | 32.7 |
| | 0.9 |
| | 1.4 |
| | 1.5 |
| | (0.2 | ) | 32.2 |
| | (2.4 | ) | | 0.7 |
| | (0.9 | ) | | (1.0 | ) |
Industrial | 23.8 |
| | 1.1 |
| | 2.0 |
| | 1.0 |
| | 1.5 |
| 23.5 |
| | (1.0 | ) | | (0.2 | ) | | (0.1 | ) | | (0.9 | ) |
Other | 0.6 |
| | (0.2 | ) | | 0.5 |
| | (0.1 | ) | | 0.3 |
| 0.6 |
| | (4.2 | ) | | (3.5 | ) | | (4.0 | ) | | (3.5 | ) |
Total retail | 83.8 |
| | 0.1 |
| | 3.2 |
| | 1.2 | % | | 0.5 | % | 82.4 |
| | (2.9 | ) | | 1.3 |
| | (0.4 | )% | | (0.4 | )% |
Wholesale | | | | | | | | | | | | | | | | | | |
Non-affiliates | 3.5 |
| | (19.0 | ) | | 42.6 |
| | | | | 3.3 |
| | (4.0 | ) | | (2.5 | ) | | | | |
Affiliates | 0.6 |
| | (50.6 | ) | | 125.4 |
| | | | | 0.8 |
| | (42.8 | ) | | 153.5 |
| | | | |
Total wholesale | 4.1 |
| | (25.5 | ) | | 54.2 |
| | | | | 4.1 |
| | (15.3 | ) | | 18.8 |
| | | | |
Total energy sales | 87.9 |
| | (1.5 | )% | | 5.3 | % | | | | | 86.5 |
| | (3.6 | )% | | 2.1 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers.
In 2015,2017, KWH sales for the residential class decreased 5.2% compared to 20142016 primarily due to milder weather in 2017. Weather-adjusted residential KWH sales decreased by 0.2% primarily due to a decline in average customer usage resulting from an
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased by 0.9% primarily due to a decline in average customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales were essentially flat primarily due to decreased demand in the firstchemicals and fourth quarterspaper sectors, offset by increased demand in the textile, non-manufacturing, and rubber sectors. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes for the period.
In 2016, KWH sales for the residential class increased 3.5% compared to 2015 primarily due to warmer weather in the third quarter 2016 as compared to the corresponding periodsperiod in 20142015 and decreasedincreased customer usage,growth, partially offset by an increase indecreased customer growth.usage. Weather-adjusted residential KWH sales increased by 1.0% primarily due to an increase of approximately 25,00028,000 residential customers during 2015. Household income, one of the primary drivers of residentialsince December 31, 2015, partially offset by a decline in customer usage had modest growth in 2015. Weather-adjusted commercial KWH sales increased by 1.5% primarily due to an increase of approximately 3,000 customers andresulting from an increase in customer usage. Weather-adjusted industrial KWH sales increased by 1.0% primarily due to increased demandmulti-family housing and efficiency improvements in the pipeline, rubber,residential appliances and paper sectors, partially offset by decreased demand in the chemicals and primary metals sectors.
In 2014, KWH sales for residential and commercial customer classes increased compared to 2013 primarily due to colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and customer growth, partially offset by decreased customer usage. Industrial sales increased in 2014 compared to 2013. Increased demand in the paper, textiles, and stone, clay, and glass sectors was the main contributor to the increase in industrial sales in 2014 compared to 2013.lighting. Weather-adjusted commercial KWH sales decreased by 0.2%1.0% primarily due to a decline in average customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by an increase of approximately 2,600 commercial customers since December 31, 2015. Weather-adjusted industrial KWH sales decreased 0.9% primarily due to decreased customer usage, largelydemand in the pipeline, primary metals, stone, clay, and glass, and textile sectors, partially offset by customer growth. Weather-adjusted residential KWH sales increased by 0.5% primarily due to customer growth, largely offset by decreased customer usage. Household income, one ofdemand in the primary drivers of residential customer usage, was flat in 2014.non-manufacturing sector.
See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the single largest expenseexpenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
Details of the Company's generation and purchased power were as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Total generation (in billions of KWHs) | 63.2 |
| | 68.4 |
| | 65.9 |
|
Total purchased power (in billions of KWHs) | 26.9 |
| | 24.8 |
| | 25.6 |
|
Sources of generation (percent) — | | | | | |
Gas | 41 |
| | 38 |
| | 39 |
|
Coal | 32 |
| | 36 |
| | 34 |
|
Nuclear | 25 |
| | 24 |
| | 25 |
|
Hydro | 2 |
| | 2 |
| | 2 |
|
Cost of fuel, generated (in cents per net KWH) — | | | | | |
Gas | 2.68 |
| | 2.36 |
| | 2.47 |
|
Coal | 3.17 |
| | 3.28 |
| | 4.55 |
|
Nuclear | 0.83 |
| | 0.85 |
| | 0.78 |
|
Average cost of fuel, generated (in cents per net KWH) | 2.36 |
| | 2.33 |
| | 2.77 |
|
Average cost of purchased power (in cents per net KWH)(*) | 4.62 |
| | 4.53 |
| | 4.33 |
|
(*) Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider.
Fuel and purchased power expenses were $2.7 billion in 2017, an increase of $23 million, or 0.9%, compared to 2016. The increase was primarily due to an $84 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $61 million related to the volume of KWHs generated and purchased primarily due to milder weather, resulting in lower customer demand.
Fuel and purchased power expenses were $2.7 billion in 2016, a decrease of $211 million, or 7.3%, compared to 2015. The decrease was primarily due to a $285 million net decrease in the average cost of fuel and purchased power due to lower coal and natural gas prices, partially offset by a $74 million net increase in the volume of KWHs generated and purchased to meet customer demand.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
Details of the Company's generation and purchased power were as follows:
|
| | | | | | | | |
| 2015 | | 2014 | | 2013 |
Total generation (billions of KWHs) | 65.9 |
| | 69.9 |
| | 66.8 |
|
Total purchased power (billions of KWHs) | 25.6 |
| | 23.1 |
| | 21.4 |
|
Sources of generation (percent) — | | | | | |
Coal | 34 |
| | 41 |
| | 35 |
|
Nuclear | 25 |
| | 22 |
| | 23 |
|
Gas | 39 |
| | 35 |
| | 39 |
|
Hydro | 2 |
| | 2 |
| | 3 |
|
Cost of fuel, generated (cents per net KWH) — | | | | | |
Coal | 4.55 |
| | 4.52 |
| | 4.92 |
|
Nuclear | 0.78 |
| | 0.90 |
| | 0.91 |
|
Gas | 2.47 |
| | 3.67 |
| | 3.33 |
|
Average cost of fuel, generated (cents per net KWH) | 2.77 |
| | 3.40 |
| | 3.32 |
|
Average cost of purchased power (cents per net KWH)* | 4.33 |
| | 5.20 |
| | 4.83 |
|
|
| |
* | Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider. |
Fuel and purchased power expenses were $2.9 billion in 2015, a decrease of $638 million, or 18.0%, compared to 2014. The decrease was primarily due to a $544 million decrease in the average cost of fuel and purchased power largely as a result of lower natural gas prices and a $228 million decrease in the volume of KWHs generated by coal, partially offset by a $134 million increase in the volume of KWHs purchased due to lower natural gas prices.
Fuel and purchased power expenses were $3.5 billion in 2014, an increase of $344 million, or 10.8%, compared to 2013. The increase was primarily due to a $292 million increase in the volume of KWHs generated and purchased due to colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand and an increase of $84 million in the average cost of purchased power primarily due to higher natural gas prices, partially offset by a $32 million decrease in the average cost of fuel primarily due to lower coal prices.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through the Company's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Fuel
Fuel expense was $2.0$1.7 billion in 2015,2017, a decrease of $514$136 million, or 20.2%7.5%, compared to 2014.2016. The decrease was primarily due to a decrease of 32.7%7.7% in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by an increase of 13.6% in the average cost of natural gas per KWH generated andgenerated. Fuel expense was $1.8 billion in 2016, a decrease of 22.2%$226 million, or 11.1%, compared to 2015. The decrease was primarily due to a decrease of 18.6% in the average cost of coal and natural gas per KWH generated, partially offset by an increase of 10.0% in the volume of KWHs generated by coal, partially offset by a 6.2% increase in the volume of KWHs generated by natural gas. Fuel expense was $2.5 billion in 2014, an increase of $240 million, or 10.4%, compared to 2013. The increase was primarily due to an increase of 5.7% in the volume of KWHs generated as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand and a 2.4% increase in the average cost of fuel per KWH generated primarily due to higher natural gas prices, partially offset by lower coal prices.coal.
Purchased Power - Non-Affiliates
Purchased power expense from non-affiliates was $289$416 million in 2015,2017, an increase of $2$55 million, or 0.7%15.2%, compared to 2014.2016. The increase was primarily due to a 28.1%13.4% increase in the volume of KWHs purchased primarily due to unplanned outages at Company-owned generating units. Purchased power expense from non-affiliates was $361 million in 2016, an increase of $72 million, or 24.9%, compared to 2015. The increase was primarily due to a 36.8% increase in the volume of KWHs purchased to meet customer demand, partially offset by a 19.8%12.5% decrease in the average cost per KWH purchased due to lower natural gas prices. Purchased power expense from non-affiliates was $287 million in 2014, an increase of $63 million, or 28.1%, compared to 2013. The increase was primarily due to a 6.1% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 22.0% increase in the volume of KWHs purchased to meet higher customer demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
Purchased power expense from affiliates was $575$622 million in 2015, a decrease2017, an increase of $126$104 million, or 18.0%20.1%, compared to 2014.2016. The decreaseincrease was primarily due to a decrease of 17.4% in the average cost per KWH purchased reflecting lower natural gas prices, partially offset by an 8.1%7.0% increase in the volume of KWHs purchased to meet customer demand. Purchased power expense from affiliates was $701 million in 2014, ansupport Southern Company system transmission reliability and as a result of unplanned outages at Company-owned generating units and a 1.8% increase of $41 million, or 6.2%, compared to 2013. The increase was primarily due to an increase of 5.8% in the average cost per KWH purchased reflectingprimarily resulting from higher natural gas prices andprices. Purchased power expense from affiliates was $518 million in 2016, a 5.6% increasedecrease of $57 million, or 9.9%, compared to 2015. The decrease was primarily due to an 11.9% decrease in the volume of KWHs purchased due to meet higher customer demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014lower market cost of available energy as compared to Southern Company system resources, partially offset by a 6.2% increase in the corresponding periods in 2013.average cost per KWH purchased.
Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
In 2015,2017, other operations and maintenance expenses decreased $58$307 million, or 3.0%15.7%, compared to 2014.2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $51$85 million in transmission operating expenses, primarily due to gains from sales of assets and billing adjustments with integrated transmission system owners, $28generation maintenance costs, $49 million in employee benefits, $46 million in transmission and distribution overhead line maintenance, and $11$22 million in workers compensationcustomer accounts and legal expensesales costs. Other factors include a $40 million increase in gains from sales of assets, a $19 million decrease in scheduled generation outage costs, and a $15 million decrease in customer assistance expenses, primarily in demand-side management costs related to the timing of new programs.
In 2016, other operations and maintenance expenses increased $116 million, or 6.3%, compared to 2015. The increase was primarily due to a lower volume$37 million decrease in gains from sales of claims,assets, a $36 million charge in connection with cost containment activities, a $30 million increase in overhead line maintenance, a $15 million increase in hydro and gas generation maintenance, a $10 million increase in customer accounts, service, and sales costs, and a $7 million increase in material costs related to higher generation volumes. The increase was partially offset by an increasea decrease of $33$36 million in employee benefits including pension costs.
See FUTURE EARNINGS POTENTIAL – "Other Matters" herein and Note 2 to the financial statements for additional information on pension costs.
In 2014, other operations and maintenance expenses increased $248 million, or 15.0%, compared to 2013. The increase was primarily due to increases of $74 million in transmission and distribution overhead line maintenance expenses, $58 million in generation expense to meet higher demand, $52 million in scheduled outage-related costs, $35 million in customer assistance expenses related to customer incentivethe cost containment and demand-side managementmodernization activities and pension costs, and $11 million in the storm damage accrual as authorized in the 2013 ARP.respectively.
Depreciation and Amortization
Depreciation and amortization remained flatincreased $40 million, or 4.7%, in 20152017 compared to 20142016. The increase was primarily due to a $16$33 million increase related to additional plant in service and a $14 million decrease relatedin amortization of regulatory liabilities
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
related to other cost of removal obligations that expired in December 2016, partially offset by a $23$9 million decrease in depreciation related to generating unit retirements in 2016 and amortization of regulatory assets related to certain cancelled environmental and fuel conversion projects that expired in December 2016.
Depreciation and amortization increased $9 million, or 1.1%, in 2016 compared to 2015. The increase was primarily due to a $34 million increase related to additional plant in service.
Depreciationservice and amortization increased $39a $9 million or 4.8%,increase in 2014 comparedother cost of removal, partially offset by an $18 million decrease related to 2013. The increase was primarily due to decreases of $36 million and $17 million in amortization of regulatory liabilities related to state income tax creditscertain nuclear construction financing costs that was completed in December 20132015 and other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $14$16 million in depreciation and amortization also as authorized in the 2013 ARP.related to unit retirements.
See Note 1 to the financial statements under "Depreciation and Amortization" for additional information.
Taxes Other Than Income Taxes
In 2015, taxes other than income taxes decreased $18 million, or 4.4%, compared to 2014. The decrease was primarily due to decreases of $15 million in municipal franchise fees related to lower retail revenues and $5 million in payroll taxes.
In 2014,2017, taxes other than income taxes increased $27$4 million, or 7.1%1.0%, compared to 2013. The increase was2016. In 2016, taxes other than income taxes increased $14 million, or 3.6%, compared to 2015 primarily due to increases of $24$7 million in municipal franchise fees related to higher retail revenuesproperty taxes as a result of an increase in the assessed value of property and $9$4 million in payroll taxes, partially offset by a $6 million decrease in property taxes.
Interest Expense, Net of Amounts Capitalized
In 2015,2017, interest expense, net of amounts capitalized increased $15$31 million, or 4.3%8.0%, fromcompared to the prior year primarily due to an increase in outstanding borrowings.
In 2016, interest expense, net of amounts capitalized increased $25 million, or 6.9%, compared to the prior year. The increase was primarily due to a $23$34 million increase in interest due to additional long-term debt borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an $11 million decrease in interest on senior notes due to redemptions and maturities.
In 2014, interest expense, netincrease of amounts capitalized decreased $13 million, or 3.6%, from the prior year. The decrease was primarily due to a $40 million decrease in interest on long-term debt resulting from redemptions and refinancing of long-term
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
debt at lower interest rates and a $4 million increase in interest capitalized as a result of increased construction activity, partially offset by a $32 million increase in interest on outstanding long-term debt borrowings from the FFB.AFUDC debt.
Other Income (Expense), Net
In 2015, other income (expense), net increased $38 million from the prior year primarily due to increases of $9 million in wholesale operating fee revenue and $9 million in customer contributions in aid of construction, as well as a $9 million decrease in donations.
In 2014,2017, other income (expense), net decreased $12$5 million fromcompared to the prior year primarily due to a $9$10 million increase in donations and an $8 million decrease in AFUDC equity resulting from higher short-term borrowings, partially offset by a $7 million increase in third party infrastructure services revenue and a $6 million increase in wholesale operating fee revenue partially offset by an increase in AFUDC equityassociated with contractual targets.
In 2016, other income (expense), net decreased $23 million compared to the prior year primarily due to an increasedecreases of $8 million in customer contributions in aid of construction, related to ongoing environmental$6 million in wholesale operating fee revenue associated with contractual targets, and transmission projects.$4 million in gains on purchases of state tax credits.
Income Taxes
Income taxes increased $40$50 million, or 5.5%6.4%, in 20152017 compared to the prior year primarily due to higher pre-tax earnings, and the recognition in 2014 of tax benefitspartially offset by an adjustment related to emissions allowancesTax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and state apportionment.Note 5 to the financial statements for additional information.
Income taxes increased $6$11 million, or 0.8%1.4%, in 20142016 compared to the prior year primarily due to higher pre-tax earnings, and an increasepartially offset by decreases in non-deductible book depreciation partially offset byand increased state investment tax credits.
Dividends on Preferred and Preference Stock
Dividends on preferred and preference stock decreased $3 million, or 17.6%, in 2017 compared to the recognitionprior year due to the redemption in October 2017 of tax benefits relatedall outstanding shares of the Company's preferred and preference stock. See Note 6 to emission allowances and state apportionment, an increase in non-taxable AFUDC equity, and state income tax credits.the financial statements under "Outstanding Classes of Capital Stock" for additional information.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service areaterritory located withinin the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
Company to retail customers are set by the Georgia PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Electric Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the completion and subsequent operation of ongoing construction projects, primarilynext several years. Plant Vogtle Units 3 and 4.4 construction and rate recovery are also major factors. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which, among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate Plans" and "Current and Deferred Income Taxes," respectively, for additional information.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to federal and statethe transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental statuteslaws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the Company's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. The Company's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
Environmental Statutes and Regulations
General
The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the Company had invested approximately $5.0 billion in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $0.3 billion, $0.4 billion, and $0.3 billion for 2015, 2014, and 2013, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $0.7 billion from 2016 through 2018, with annual totals of approximately $0.3 billion, $0.2 billion, and $0.2 billion for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with closure in place or by other methods, and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.
Air Quality
ComplianceThrough 2017, the Company has invested approximately $5.5 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $0.3 billion, $0.2 billion, and $0.3 billion for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $1.2 billion from 2018 through 2022, with annual totals of approximately $0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimates do not include any potential compliance costs associated with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Additional controls are currently planned or under consideration to further reduce airregulation of CO2 emissions maintain compliance with existing regulations, and meet new requirements.
In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions to April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each Company unit. On June 29, 2015, the U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from fossil fuel-fired electric generating units. On December 15, 2015,See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the U.S. CourtDisposal of Appeals for the District of Columbia Circuit remanded the MATSCoal Combustion Residuals from Electric Utilities rule to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding(CCR Rule), which are reflected in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliance requirements and deadlines.
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in 2012. The only area within the Company's service territory designated as an ozone nonattainment area for the 2008 standard is a 15-county area within metropolitan Atlanta. On October 26, 2015, the EPA published a more stringent eight-ARO liabilities. See FINANCIAL
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
hourCONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, NAAQS. This new standard could potentiallyparticulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational fuel changes and couldcosts. NAAQS requirements can also adversely affect the siting of new generating facilities. States will recommend area designations by October 2016, andIn 2015, the EPA is expected to finalize them by October 2017.
published a more stringent eight-hour ozone NAAQS. The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company's service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS and the EPA has officially redesignated former nonattainment areas within the service territory as attainment for these standards. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated finalplans to complete designations for the 2012 annual standard in December 2014,this rule by no later than April 30, 2018 and no new nonattainment areas were designatedintends to designate an eight-county area within the Company's service territory. The EPA has, however, deferred designation decisions for certain areas in Georgia.
Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010.metropolitan Atlanta as nonattainment. No other areas within the Company's service territory have been or are anticipated to be designated as nonattainment under this rule. However,the 2015 ozone NAAQS. In 2010, the EPA has finalized a data requirements rule to support additional designation decisionsrevised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the future, which could result in nonattainment designations for areas within the Company's service territory. Implementationvicinity of the revisedCompany-owned SO2 standard could require additional reductions insources have been designated nonattainment under the 2010 one-hour SO2 emissionsNAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance and operational costs.costs could result.
The Company's service territory is subject toIn 2011, the requirements ofEPA finalized the Cross StateCross-State Air Pollution Rule (CSAPR). and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that limitsaddresses the impacts of the interstate transport of SO2 and nitrogen oxideNOX emissions from fossil fuel-fired power plants located in 28upwind states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,the eastern half of the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Georgia, Alabama, and Florida, but rejected all other pending challengeson air quality in downwind states. The Company has fossil fuel-fired generation subject to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,these requirements. In October 2016, the EPA published a proposed revision tofinal rule that revised the CSAPR that would revise existing ozone-seasonseasonal NOX program, establishing more stringent NOX emissions budgets in Alabama. Georgia's seasonal NOX budget remains unchanged. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for nitrogen oxide in Alabama and would remove Florida from the CSAPR program. The EPA proposes to finalize this rulemaking by summer 2016.Company.
The EPA finalized regional haze regulations in 2005 with aand 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, (primarilyincluding national parks and wilderness areas)areas. States must submit a revised state implementation plan (SIP) to the EPA by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieveJuly 31, 2021, demonstrating reasonable progress toward the naturaltowards achieving visibility conditions goal by 2018 and for each 10-year period thereafter.improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Georgia Alabama, and Florida)Alabama) to revise or remove the provisions of their State Implementation Plans (SIPs) relating to the regulation ofSIPs regulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in increased operations and maintenance costs for the Company. The EPA has not yet responded to the SIP revisions proposed by no later than November 22, 2016.the State of Georgia.
Water Quality
In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities in order to minimize their effects on fish and other aquatic life. The Company has developed and continually updates a comprehensive environmental compliance strategyregulation requires plant-specific studies to assess compliance obligations associated withdetermine applicable measures to protect organisms that either get caught on the current and proposed environmental requirements discussed above. As partintake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this strategy, the Company has developed a compliance plan for the MATS rule which includes reliance on existing emission control technologies, the construction of baghouses to provide an additional level of control on the emissions of mercury and particulates from certain generating units, the use of additives or other injection technology, the use of additional natural gas capability, and unit retirements. Additionally, certain transmission system upgrades are required. The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisionsoutcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
In 2015, the proposedEPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and final rules, the resolution of pendingimposes stringent arsenic, mercury, selenium, and future legal challenges, and/nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the developmentinstallation and implementationoperation of rules atnew ash and wastewater management systems. Compliance with the state level. These regulations could result in significant additionalELG rule is expected to require capital expenditures and complianceincreased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could affect future unit retirementpotentially revise the limitations and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs.
In addition to the federal air quality laws described above, the Company has also been subject to the requirementsapplicability dates of the 2007 State of Georgia Multi-Pollutant Rule.ELG rule. The Multi-Pollutant Rule and a companion rule required reductionsEPA expects to finalize this rulemaking in emissions of mercury, SO2, and nitrogen oxide state-wide through the installation of specified control technologies and a 95% reduction in SO2 emissions at certain coal-fired generating units by specific dates between 2008 and 2015. In 2015, the Company completed2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
implementation of the measures necessary to comply with the Georgia Multi-Pollutant Rule at all 16 of its coal-fired generating units required to be controlled under the rule.
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014. The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.
On November 3, 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and implementation of the final rule and cannot be determined at this time.
On June 29,In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule revisingthat revised the regulatory definition of waters of the U.S.United States (WOTUS) for all Clean Water Act (CWA)CWA programs. The final rule significantly expandsexpanded the scope of federal jurisdiction under the CWAover waterbodies (such as rivers, streams, and could have significant impacts on economic development projectscanals), which could affect customer demand growth. In addition, this rule could significantly increaseimpact new generation projects and permitting and regulatoryreporting requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines.projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule became effective August 28, 2015, but on October 9, 2015,has been stayed by the U.S. Court of Appeals for the Sixth Circuit issued an order stayingsince late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the final rule. The ultimate impact of the final2015 WOTUS rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.to 2020.
Coal Combustion Residuals
The Company currently manages CCR at onsite units consisting of landfills and surface impoundments (CCR Units) at 11 electric generating plants, including some that have recently retired. In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the State of Georgia has its own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.
On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulatesfinalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Unitslandfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule does not automatically require closurerequires CCR units to be evaluated against a set of CCR Units but includesperformance criteria and potentially closed if minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansionsare not met. Closure of existing CCR units could require installation of equipment and infrastructure to manage CCR in accordance with the rule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in changes to deadlines and corrective action requirements.
The EPA's reconsideration of the CCR Rule is due in part to a legislative development that impacts the potential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR Rule. The Georgia Department of Natural Resources has incorporated the requirements of the CCR Rule into its solid waste regulations, which established additional requirements for all of the Company's CCR units, and active landfills. Failure to meet the minimum criteria can result in the required closure of a CCR Unit. Althoughhas requested that the EPA does not require individual states to adopt the final criteria, states have the option to incorporate the federal criteria into theirapprove its state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. The EPA's final rule continues to exclude the beneficial use of CCR from regulation.permitting program.
Based on initial cost estimates for closure in place or by other methods, and groundwater monitoring of ash ponds pursuant to the CCR Rule, the Company recorded incremental AROs relatedan update to the AROs for each CCR Rule.unit in 2015. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates. The Company is currently completing an analysis of the plan of closure for all ash ponds, including the timing of closurecost estimates as necessary. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and related cost recovery through regulated rates subject to Georgia PSC approval. Based on the results of that analysis, the Company may accelerate the timing of some ash pond closures which could increase its ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule cannot be determined at this timeContractual Obligations" herein and will depend on the Company's ongoing review of the CCR Rule,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2015.2017.
Environmental Remediation
The Company must comply with other environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the estimated costs to clean up known impacted sites.sites in its financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Notes 1 and 3 to the financial statements under "Environmental Remediation Recovery" and "Environmental Matters – Environmental Remediation," respectively, for additional information.
Global Climate Issues
On October 23,In 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governingrules limiting CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishesfossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goalsperformance standards for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. Atunits (known as the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adoptClean Power Plan or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. OnCPP). In February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stayCPP, which will remain in effect through the resolution of the litigation whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit orchallenging the legality of the CPP and any review by the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the Company's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, including legal challenges filed byproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the traditional operating companies; individual state implementation of the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countries and cannot be determined at this time.countries.
The EPA's greenhouse gasGHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2014 greenhouse gas
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
2016 GHG emissions were approximately 3833 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2015 greenhouse gas2017 GHG emissions on the same basis is approximately 3130 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Retail Regulatory Matters
The Company's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. The Company currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ECCR tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs on certified project costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariffs.tariff. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Rate Plans
In 2013,On January 16, 2018, the Georgia PSC votedapproved the Company's sale of its natural gas lateral pipeline serving Plant McDonough Units 4 through 6 to approveSouthern Natural Gas, L.L.C. (SNG) at net book value. Pursuant to this approval, legal transfer of the lateral pipeline is expected to occur in the fourth quarter 2018 and payment of $142 million is expected to occur in the first quarter 2020. Completion of this sale is contingent on certain conditions to be satisfied by SNG that include, among other things, expansion of the existing lateral pipeline. Southern Company Gas, an affiliate of the Company, owns a 50% equity interest in SNG. The ultimate outcome of this matter cannot be determined at this time; however, no material impact on the Company's financial statements is expected.
Rate Plans
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP. The 2013 ARP reflectswill continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement amongagreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers. See Note 3 to the Company,financial statements under "Retail Regulatory Matters – Rate Plans" for additional information regarding the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors.2013 ARP.
On December 16, 2015, inIn accordance with the 2013 ARP, the Georgia PSC approved an increaseincreases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, the Company's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014,2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00%, and the Company will refund to retail customers approximately $11$44 million in 2016,2018, as approved by the Georgia PSC on February 18, 2016.January 16, 2018. In 2015,2017, the Company's retail ROE was within the allowed retail ROE range.range, subject to review and approval by the Georgia PSC.
TheOn January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, the Company is required to file a general base rate case by July 1, 2016, in responsesubmit its analysis of the Tax Reform Legislation and related recommendations to whichaddress the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.
Renewables
In May 2014, the Georgia PSC approvedrelated impacts on the Company's application for the certificationcost of two PPAs executed in 2013 for the purchaseservice and annual revenue requirements by March 6, 2018. The ultimate outcome of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.
As part of the Georgia Power Advanced Solar Initiative (ASI), the Company executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. Two PPAs began in December 2015 and eight are expected to begin in December 2016, all of which have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, the Company expects that 249 MWs of the 515 MWs of contracted capacity willthis matter cannot be purchased from solar facilities owned or under development by Southern Power.
In October 2014, the Georgia PSC approved the Company's request to build, own, and operate three 30-MW solar generation facilitiesdetermined at three U.S. Army bases by the end of 2016. One of the three solar generation facilities began commercial operation on December 31, 2015. In addition, in December 2014, the Georgia PSC approved the Company's request to build, own, and operate a 30-MW solar generation facility at Kings Bay Naval facility. On July 21, 2015, the Georgia PSC approved the Company's request to build and operate an up to 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia. The Company subsequently determined that a 31-MW facility will be constructed on the site. On December 22, 2015, the Georgia PSC approved the Company's request to build and operate the remaining 15 MWs at a separate facility on the Fort Stewart Army base in Hinesville, Georgia. These facilities are expected to be operational by the end of 2016.
On April 7, 2015, the Georgia PSC approved the consolidation of four PPAs each with the same counterparty into two new PPAs with new biomass facilities. Under the terms of the order, the total 116 MWs from the existing four PPAs provided the capacity for two new PPAs of 58 MWs each. The new PPAs were executed on June 15, 2015 and November 23, 2015 and will begin in June 2017. See "Integrated Resource Plan" herein for additional information on renewables.this time.
Integrated Resource Plan
See "Environmental Matters" and "Rate Plans" herein for additional information regarding proposed and final EPA rules and regulations, including the MATS rule for coal- and oil-fired electric utility steam generating units, revisions to effluent limitationsELG for steam electric power plants and additional regulations of CCR and CO2.
In July 2016, the Georgia PSC approved the Company's triennial Integrated Resource Plan (2016 IRP) including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, the Plant Mitchell and Plant Kraft units were retired and the Company sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, LLC.
II-222Additionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in the Company's 2019 base rate case.
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, the Company filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. The Company also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved the Company's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in a future rate case.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved the Company's request to further lower annual billings under an interim fuel rider by approximately $313 million
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
guidelines for steam electric power plants, and additional regulations of CCR and CO2; the State of Georgia's Multi-Pollutant Rule; andeffective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review the Company's analysis ofcumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the potential costs and benefits of installing the required controls on its fossil generating units in light of these regulations.
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switchneed to natural gas as the primaryfile a fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.
In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.
On January 29, 2016,case unless the Company filed its triennial IRP (2016 IRP). The filing includeddeems it necessary to file a request to decertify Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval of the 2016 IRP. The 2016 IRP also reflects that the Company exercised its contractual option to sell its 33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 to the financial statements for additional information.
In the 2016 IRP, the Company requested reclassification of the remaining net book value of Plant Mitchell Unit 3, as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. The Company also requested that the Georgia PSC approve the deferral of the cost associated with materials and supplies remainingfuel case at the unit retirement dates to a regulatory asset, to be amortized over a period deemed appropriate by the Georgia PSC.
The decertification and retirement of these units are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's orders in the 2016 IRP and next general base rate case.
Additionally, the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand the Company's existing renewable initiatives, including ASI.
A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at thisan earlier time.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. The Company continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. On December 15, 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016.
The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon effective Januaryhorizon.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to the Company's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in the regulatory asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in the regulatory asset related to storm damage was $333 million. The rate of storm damage cost recovery is expected to be adjusted as part of the Company's next base rate case required to be filed by July 1, 2016.2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on the Company's financial statements. See Note 1 to the financial statements under "Storm Damage Recovery" for additional information regarding the Company's storm damage reserve.
Nuclear Construction
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, the Company, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners),Owners, entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement).
Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. TheUnder the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle 3 and 4 Agreement also provides for liquidated damages uponOwners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition,potential obligations under the Vogtle 3 and 4 Agreement providesAgreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for limited cost sharing byamounts owed for work performed on Plant Vogtle Units 3 and 4. The Company, acting for itself and as agent for the Vogtle Owners, forhas taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor costs under certain conditions (whichand the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have not occurred), with maximum additional capital costs under this provision attributablebeen paid or accrued as of December 31, 2017.
On June 9, 2017, the Company and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which the Company's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Company, (basedthe other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Company, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and the Company and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
II-223Additionally, on June 9, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Vogtle Services Agreement, (ii) assume and
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
Company's ownership interest)assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of approximately $114 million.the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
Effective October 23, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (and not(not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the ContractorBechtel under the Vogtle 3 and 4Bechtel Agreement. The Company's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
The Vogtle Owners may terminate the Vogtle 3 and 4Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination costs. The Contractortermination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Vogtle 3 and 4Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspension or delayssuspensions of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between the Company and the DOE, the Company is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In 2009,On November 2, 2017, the NRC issuedVogtle Owners entered into an Early Site Permit and Limited Work Authorization which allowed limited workamendment to begin ontheir joint ownership agreements for Plant Vogtle Units 3 and 4. The NRC certified4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Westinghouse Design Control Document, as amended (DCD), forVogtle Joint Ownership Agreements, the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receiptholders of at least 90% of the COLs allowed fullownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction to begin. There have been technical and procedural challengesif certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or the Company determines that any of the Company's costs relating to the construction and licensing of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the federalprimary construction contractor and state level, and additional challenges may arise(ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against the Company or Southern Nuclear for any action or inaction in connection with their performance as construction proceeds.agent for the Vogtle Owners is limited to removal of the Company and/or Southern Nuclear as agent, except in cases of willful misconduct.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4.4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base duringcertified capital cost of $4.418 billion. As of December 31, 2017, the construction period. The Georgia PSC approved an initial NCCR tariffCompany had recovered approximately $1.6 billion of approximately $223 million effectivefinancing costs. On January 1, 2011, as well as increases30, 2018, the Company filed to decrease the NCCR tariff ofby approximately $35 million, $50 million, $60 million, $27effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, the Customer Refunds ordered by the Georgia PSC aggregating approximately $188 million, and $19 million effective January 1, 2012, 2013, 2014, 2015,the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and 2016, respectively.will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
The Company is required to file semi-annual Vogtle Construction Monitoring (VCM)VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by the Company increase by 5% above the certified cost or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, the Company requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the staff of the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company.
On April 15, 2015,December 20, 2016, the Georgia PSC issuedvoted to approve a procedural ordersettlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the twelfthfifteenth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order,report. On December 21, 2017, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will be included in rate base, provided the Company shows the costsvoted to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.approve
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
In 2012,(and issued its related order on January 11, 2018) certain recommendations made by the Company in the seventeenth VCM report and modifying the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertionCost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the Contractor thatJanuary 11, 2018 order, resolved the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitledfollowing regulatory matters related to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014,4: (i) none of the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional$3.3 billion of costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on the Company's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).
Onincurred through December 31, 2015 Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, the Company, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increasesreflected in the contract price by clarifying and limitingfourteenth VCM report should be disallowed from rate base on the circumstances that constitute nuclear regulatory changes in law;basis of imprudence; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that the Company, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, the Company paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides forwas reasonable and prudent and none of the resolution of other open existing items relatingamounts paid pursuant to the scopeContractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the projectburden of proof on any party challenging such costs, (b) the Company would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Vogtle 3Guarantee Settlement Agreement and 4 Agreement, including cyber security,for which costs were reflected in the Company's previously disclosed in-service cost estimate. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with theCustomer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissedshould be completed, with prejudice.
On January 21, 2016, the Company submitted the Contractor Settlement AgreementSouthern Nuclear serving as project manager and the related amendment to the Vogtle 3Bechtel as primary contractor; (v) approved and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered the Company to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement anddeemed reasonable the Company's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost andrevised schedule are reasonable. Following the Company's filing under the order, the Staff will conduct a review of all costs incurred related toplacing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the schedulerevised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than the Company's average cost of long-term debt); (viii) reduced the ROE used for completionAFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to the Company's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than the Company's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which the Company's seventeenth VCM report are based do not materialize, both the Company and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company's results of operations, financial condition, and liquidity.
The IRS allocated PTCs to each of Plant Vogtle Units 3 and 4, andwhich originally required the Contractor Settlement Agreement andapplicable unit to be placed in service before 2021. Under the Staff is authorized to engage in related settlement discussions with the Company and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respect to the statusBipartisan Budget Act of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of the Company's portion of the PTCs is approximately $500 million per unit.
In its January 11, 2018 order, the Georgia PSC will then conduct a hearingalso approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing the Company to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
June 30, 2017). The Georgia PSC has approved thirteenseventeen VCM reports covering the periods through June 30, 2015,2017, including total construction capital costs incurred which through that date totaled $3.1of $4.4 billion. On February 26, 2016, theThe Company filedexpects to file its fourteentheighteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. The Company ison February 28, 2018 requesting approval of $160approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred during that period. The Company anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion.July 1, 2017 through December 31, 2017. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6$4.8 billion as of December 31, 2015.2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
II-225The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
Cost and Schedule
The Company's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issuesmatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or the Company (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.costs.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of December 31, 2017, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among the Company, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
Bonus DepreciationFederal Tax Reform Legislation
On December 18, 2015,22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Act.
In addition, under the Tax Reform Legislation, net operating losses (NOLs) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $8 million, a $150 million decrease in regulatory assets, and a $3.1 billion increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Georgia PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the Company's rate filing to reflect the impacts of the Tax Reform Legislation.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus depreciation was extended for qualified propertyDepreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service overafter September 27, 2017 remain eligible for bonus depreciation under the next five years.PATH Act. The PATH Act allowsallowed for 50% bonus depreciation for 2015 2016, and 2017;through 2017, 40% bonus depreciation for 2018;2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50%Based on provisional estimates, bonus depreciation is expected to result in approximately $220 million of positive cash flows of approximately $270 million for the 20152017 tax year and approximately $310$120 million for the 20162018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The Company regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies, in 2017, the Company initiated the closure of its remaining payment offices and an employee attrition plan affecting approximately 300 positions. Charges associated with these activities did not have a material impact on the Company's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Electric
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
Utility Regulation
The Company is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate Plans" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, and facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
The Company previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule discussed above. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place or by other methods.closure. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" for additional information.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ForBeginning in 2016, the Company has adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense will decreasedecreased by approximately $35 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $10an $11 million or less change in total annual benefit expense and a $141$172 million or less change in projected obligations.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers(ASC 606), revisesreplacing the existing accounting standard and industry specific guidance for revenue recognition effectivewith a five-step model for fiscal years beginning after December 15, 2017.recognizing and measuring revenue from contracts with customers. The Company continues to evaluate the requirements of ASC 606. The ultimate impactunderlying principle of the new standard has not yet been determined.is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
On April 7, 2015,Most of the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – ImputationCompany's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of Interest (Subtopic 835-30):Simplifyingall revenue streams and determined that the Presentationadoption of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented inASC 606 will not change the balance sheetcurrent timing of revenue recognition for such transactions. Some revenue arrangements, such as a direct deductionenergy-related derivatives, are excluded from the carrying amountscope of that debt liabilityASC 606 and, is effectivetherefore, will be accounted for fiscal years beginning after December 15, 2015. As permitted, theand disclosed separately from revenues under ASC 606. The Company electedhas concluded contributions in aid of construction are not in scope for ASC 606 and will continue to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presentedbe accounted for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $124 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred chargesproperty, plant, and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Notes 6 and 10 to the financial statements for disclosures impacted by ASU 2015-03.equipment.
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Notes 2 and 10 to the financial statements for disclosures impacted by ASU 2015-07.
On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
amounts. The new guidance resultedstandard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a reclassificationcumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to PPAs and cellular towers where the Company is the lessee and to outdoor lighting where the Company is the lessor. The Company is currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from prepaidoperations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income taxesstatement. The capitalization of $34 million to non-current accumulated deferred income taxesonly the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption ofoperating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2015-17 did not have an2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the results of operations, cash flows, orFASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial condition ofand non-financial hedging strategies eligible for hedge accounting, amends the Company. See Note 5 to therelated presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements for disclosures impacted by ASU 2015-17.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2015.2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to meet projected long-term demand requirements,build new generation facilities, including Plant Vogtle Units 3 and 4, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 20162018 through 2018,2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Projected capital expenditures in that period include investments to build new generation facilities, including Plant Vogtle Units 3 and 4, to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
external securities issuances, and capitalequity contributions from Southern Company, as well as by accessing borrowings from financial institutions, and borrowings through the FFB. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's investments in the qualified pension plan and nuclear decommissioning trust funds decreasedincreased in value as of December 31, 20152017 as compared to December 31, 2014.2016. No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated during 2016.2018. The Company also funded approximately $5 million to its nuclear decommissioning trust funds in 2015.2017. See "Contractual Obligations" herein and Notes 1 and 2 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.
Net cash provided from operating activities totaled $2.5$1.9 billion in 2015, an increase2017, a decrease of $154$513 million from 2014,2016, primarily due to increased fuel cost recovery, partially offset by the timing of vendor payments.payments and increases in under-recovered fuel costs and prepaid federal income taxes, partially offset by a decrease in voluntary contributions to the qualified pension plan. Net cash provided from operating activities totaled $2.4 billion in 2014,2016, a decrease of $403$92 million from 2013,2015, primarily due to the timing of rate recovery for fuel and storm restoration costs,voluntary contribution to the qualified pension plan in 2016, partially offset by higher retail operating revenuesthe timing of vendor payments. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and lower fuel inventory additions.Note 5 to the financial statements for additional information regarding federal income taxes.
Net cash used for investing activities totaled $1.9$0.9 billion, $2.2$2.3 billion, and $1.9 billion in 2015, 2014,2017, 2016, and 2013,2015, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of generation, transmission, and distribution facilities;facilities including Plant Vogtle Units 3 and purchase4, partially offset in 2017 by $1.7 billion in payments received under the Guarantee Settlement Agreement; and purchases of nuclear fuel. The majority of funds needed for gross property additions for the last several years has been provided from operating activities, capital contributions from Southern Company, and the issuance of debt. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information.information on the Guarantee Settlement Agreement and construction of Plant Vogtle Units 3 and 4.
Net cash used for financing activities totaled $151 million, $142 million, and $530 million $163 million,for 2017, 2016, and $891 million for 2015, 2014, and 2013, respectively. The increase in cash used in 20152017 compared to 20142016 was primarily due to the redemption and maturity of senior notes in 2015. Thea decrease in cash usednotes payable, a decrease in 2014 compared to 2013 was primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, and the redemption of all outstanding shares of the Company's preferred and preference stock, partially offset by FFB loan issuance costshigher issuances of senior notes and junior subordinated notes and a reductiondecrease in maturities of senior notes. The decrease in cash used in 2016 compared to 2015 was primarily due to higher capital contributions from Southern Company, a decrease in redemptions and maturities of senior notes, and an increase in short-term debt.debt, partially offset by higher common stock dividends and a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes in 20152017 included an increase of $1.8$3.1 billion in totaldeferred credits related to income taxes and a decrease of $2.8 billion in accumulated deferred income taxes primarily resulting from the impacts of Tax Reform Legislation; an increase in property, plant, and equipment dueof $2.0 billion to gross property additions as described above, an increase in other regulatory assets, deferredcomply with environmental standards and the construction of $399 million primarily related to AROsgeneration, transmission, and deferred plant retirement costs, an increasedistribution facilities, partially offset by payments received under the Guarantee Settlement Agreement of $615 million in long-term debt,$1.7 billion, net of joint owner portion; and an increase of $661 million$1.2 billion in AROs.long-term debt primarily due to issuances of senior notes and junior subordinated notes. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 15 to the financial statements for additional information.information on Tax Reform Legislation and Note 3 to the financial statements under "Retail Regulatory Matters – Nuclear Construction" for additional information on the Guarantee Settlement Agreement.
The Company's ratio of common equity to total capitalization includingplus short-term debt was 49.9% in 201549.7% at December 31, 2017 and 50.4% in 2014.50.0% at December 31, 2016. See Note 6 to the financial statements for additional information.
Sources of Capital
Except as described below with respect to the DOE loan guarantees, theThe Company plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
short-term debt, external security issuances, term loans, andborrowings from financial institutions, equity contributions from Southern Company.Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approvals, prevailing market conditions, and other factors.
In addition,2014, the Company may make borrowings through a loan guarantee agreement (Loanentered into the Loan Guarantee Agreement) betweenAgreement with the Company and the DOE, under which the proceeds of whichborrowings may be used to reimburse the Company for a portionEligible Project Costs incurred in connection with its construction of certain costs of construction relating to Plant Vogtle Units 3
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2017 Annual Report
and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs).4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by the Company under a multi-advance credit facility (FFB Credit Facility) among the Company, the DOE, and the FFB. Eligible Project Costs incurred throughAs of December 31, 2015 would allow for borrowings of up to $2.32017, the Company had borrowed $2.6 billion under the FFB Credit Facility, of whichFacility. On July 27, 2017, the Company has borrowed $2.2 billion.entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.
On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note 3 to the financial statements under "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
The issuance of long-term securities by the Company is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
As ofAt December 31, 2015,2017, the Company's current liabilities exceeded current assets by $772 million primarily due to$521 million. The Company's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt that is dueand the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in one year. cash needs.
The Company intends to utilize operating cash flows, as well as FFBexternal security issuances, borrowings commercial paper, lines of credit, bank notes, and external securities issuances, as market conditions permit, andfrom financial institutions, equity contributions from Southern Company, and borrowings from the FFB to fund its short-term capital needs. The Company has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs.
At December 31, 2015,2017, the Company had approximately $67$852 million of cash and cash equivalents. CommittedA committed credit arrangementsarrangement with banks at December 31, 2015 were2017 was $1.75 billion of which $1.73 billion was unused. These credit arrangements expire in 2020.
In August 2015,May 2017, the Company amended and restated its multi-year credit arrangement which, among other things, extended the maturity date from 20182020 to 2020. The Company increased its borrowing ability by $150 million under its facility maturing in 2020 and terminated its aggregate $150 million facilities maturing in 2016.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.2022.
This bank credit arrangement, as well as the Company's term loan arrangements, contains a covenant that limits debt levels and contains a cross accelerationcross-acceleration provision to other indebtedness (including guarantee obligations) of the Company. Such cross accelerationcross-acceleration provision to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. TheAt December 31, 2017, the Company is currentlywas in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, the Company expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 20152017 was approximately $872 million.$550 million as compared to $868 million at December 31, 2016. In addition, at December 31, 2015,2017, the Company had $69$469 million of fixed rate pollution control revenue bonds outstanding that were required to be reofferedremarketed within the next 12 months.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) | Short-term Debt at the End of the Period |
| Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Amount Outstanding |
| Weighted Average Interest Rate |
| Average Amount Outstanding |
| Weighted Average Interest Rate |
| Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) | (in millions) |
|
|
| (in millions) |
|
|
| (in millions) |
December 31, 2017: | |
|
|
|
|
|
|
|
|
|
Commercial paper | | $ | — |
|
| — | % |
| $ | 135 |
|
| 1.3 | % |
| $ | 760 |
|
Short-term bank debt | | 150 |
|
| 2.2 | % |
| 292 |
|
| 2.0 | % |
| 800 |
|
Total | | $ | 150 |
|
| 2.2 | % |
| $ | 427 |
|
| 1.8 | % |
|
|
|
December 31, 2016: | |
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper | | $ | 392 |
|
| 1.1 | % |
| $ | 87 |
|
| 0.8 | % |
| $ | 443 |
|
December 31, 2015: | | | | | | | | | |
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper | $ | 158 |
| | 0.6 | % | | $ | 234 |
| | 0.3 | % | | $ | 678 |
| $ | 158 |
|
| 0.6 | % |
| $ | 234 |
|
| 0.3 | % |
| $ | 678 |
|
Short-term bank debt | — |
| | — | % | | 62 |
| | 0.8 | % | | 250 |
| — |
|
| — | % |
| 62 |
|
| 0.8 | % |
| 250 |
|
Total | $ | 158 |
| | 0.6 | % | | $ | 296 |
| | 0.4 | % | | | $ | 158 |
|
| 0.6 | % |
| $ | 296 |
|
| 0.4 | % |
|
|
|
December 31, 2014: | | | | | | | | | | |
Commercial paper | $ | 156 |
| | 0.3 | % | | $ | 280 |
| | 0.2 | % | | $ | 703 |
| |
Short-term bank debt | — |
| | — | % | | 56 |
| | 0.9 | % | | 400 |
| |
Total | $ | 156 |
| | 0.3 | % | | $ | 336 |
| | 0.3 | % | | | |
December 31, 2013: | | | | | | | | | | |
Commercial paper | $ | 647 |
| | 0.2 | % | | $ | 166 |
| | 0.2 | % | | $ | 702 |
| |
Short-term bank debt | 400 |
| | 0.9 | % | | 96 |
| | 0.9 | % | | 400 |
| |
Total | $ | 1,047 |
| | 0.5 | % | | $ | 262 |
| | 0.5 | % | | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month12-month periods ended December 31, 2015, 2014,2017, 2016, and 2013.2015. |
The Company believes the need for working capital can be adequately met by utilizing the commercial paper programs,program, lines of credit, short-term bank notes, and operating cash flows.
Financing Activities
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Senior Notes
In April 2015,March 2017, the Company redeemed $125issued $450 million aggregate principal amount of its Series Y 5.80%2017A 2.00% Senior Notes due April 15, 2035.
In August 2015, the Company'sMarch 30, 2020 and $400 million aggregate principal amount of Series 2012C 0.75% Senior Notes matured.
In November 2015, the Company's $400 million aggregate principal amount of Series 2012D 0.625% Senior Notes matured.
In December 2015, the Company issued $500 million aggregate principal amount of Series 2015A 1.95%2017B 3.25% Senior Notes due December 1, 2018.March 30, 2027. The proceeds were used to repay at maturity $250 million aggregate principal amount of the Company's Series Z 5.25% Senior Notes due December 15, 2015, to repay a portion of the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In June 2017, the Company repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.
In August 2017, the Company issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay the Company's $50 million short-term floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
Junior Subordinated Notes
In September 2017, the Company issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of the Company's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of the Company's 6.50% Series 2007A Preference Stock.
Pollution Control Revenue Bonds
In April 2015,2017, the Company purchased and held $65$27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), SecondFifth Series 2008. The1995. In October 2017, the Company reofferedremarketed these bonds to the public in May 2015.public.
In May 2015, the Company reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by the Company since 2013.
In July 2015, $97.925 million aggregate principal amount of the Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
In August 2015, in connection with optional tenders,2017, the Company repurchasedpurchased and reoffered to the public $94.6held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013.
1997. In November 2015,October 2017, the Company reofferedremarketed these bonds to the public $89.2 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009 and $46 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996, which had been previously repurchased and held by the Company since 2010.
DOE Loan Guarantee Borrowings
In June and December 2015, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million and $400 million, respectively. The interest rate applicable to the $600 million principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072%, both for an interest period that extends to the final maturity date of February 20, 2044. The proceeds were used to reimburse the Company for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
Under the Loan Guarantee Agreement, the Company is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of the Company or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information.public.
Other
In March 2015,June 2017, the Company entered into a $250 million aggregate principal amount three-monththree floating rate bank loanloans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, bearing interest based on one-month LIBOR. Also in June 2017, the Company borrowed $500 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by the Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of the Company's existing indebtedness and for working capital and other general corporate purposes, andincluding the Company's continuous construction program.
In August 2017, the Company repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, the Company amended its $100 million floating rate bank loan was repaid at maturity.to extend the maturity date from June 28, 2018 to October 26, 2018.
In December 2015,2017, the Company entered into interestrepaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
Subsequent to December 31, 2017, the Company repaid its outstanding $150 million and $100 million floating rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $500 million.bank loans due May 31, 2018 and October 26, 2018, respectively.
Credit Rating Risk
TheAt December 31, 2017, the Company doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at December 31, 20152017 were as follows:
| | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| (in millions) | (in millions) |
At BBB- and/or Baa3 | $ | 102 |
| $ | 87 |
|
Below BBB- and/or Baa3 | $ | 1,361 |
| $ | 1,055 |
|
Included in these amounts are certain agreements that could require collateral in the event that onethe Company or more Southern Company system power pool participantsAlabama Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On August 17, 2015,March 20, 2017, Moody's revised its rating outlook for the Company from stable to negative.
On March 24, 2017, S&P downgraded therevised its consolidated long-term issuercredit rating ofoutlook for Southern Company and its subsidiaries (including the Company) from stable to A- from A. S&P revised itsnegative.
On March 30, 2017, Fitch placed the ratings of the Company on rating watch negative.
While it is unclear how the credit rating outlookagencies, the FERC, and the Georgia PSC may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from negativeoperations to stable. Separately, on August 24, 2015, S&P reviseddebt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters – Rate Plans" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
rating outlook from stable to negative following the announcement of the proposed merger of a wholly-owned direct subsidiary of Southern Company with and into AGL Resources Inc.
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $1.8$1.9 billion of long-term variable interest rate exposure at January 1, 2016December 31, 2017 was 1.32%2.66%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $18$19 million at January 1, 2016.December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements for additional information.
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. The Company had no material change in market risk exposure for the year ended December 31, 20152017 when compared to the December 31, 20142016 reporting period.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
| | | 2015 Changes | | 2014 Changes | 2017 Changes | | 2016 Changes |
| Fair Value | Fair Value |
| (in millions) | (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (20 | ) | | $ | (16 | ) | $ | 36 |
| | $ | (13 | ) |
Contracts realized or settled: | | | | | | |
Swaps realized or settled | 2 |
| | 2 |
| (13 | ) | | (2 | ) |
Options realized or settled | 18 |
| | 8 |
| (1 | ) | | 11 |
|
Current period changes(*): | | | | | | |
Swaps | — |
| | (1 | ) | (28 | ) | | 31 |
|
Options | (13 | ) | | (13 | ) | (7 | ) | | 9 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (13 | ) | | $ | (20 | ) | $ | (13 | ) | | $ | 36 |
|
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts for the years ended December 31 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| mmBtu Volume | mmBtu Volume |
| (in millions) | (in millions) |
Commodity – Natural gas swaps | — |
| | 4 |
| 146 |
| | 128 |
|
Commodity – Natural gas options | 50 |
| | 42 |
| 17 |
| | 27 |
|
Total hedge volume | 50 |
| | 46 |
| 163 |
| | 155 |
|
There were no swaps outstanding as of December 31, 2015. The weighted average swap contract cost above market prices was $0.68approximately $0.08 per mmBtu as of December 31, 2014.2017. The weighted average swap contract cost below market prices was approximately $0.23 per mmBtu as of December 31, 2016. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through the Company's fuel cost recovery mechanism.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 2015 Annual Report
At December 31, 20152017 and 2014,2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program, which had a time horizon up to 2448 months. On December 15, 2015, the Hedging
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. Hedging Power Company 2017 Annual Report
gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2.2 of the fair value hierarchy. See Note 10 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 20152017 were as follows:
| | | Fair Value Measurements December 31, 2015 | Fair Value Measurements December 31, 2017 |
| Total | | Maturity | Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 | Fair Value | | Year 1 | | Years 2&3 |
| (in millions) | (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (13 | ) | | (10 | ) | | (3 | ) | (13 | ) | | (7 | ) | | (6 | ) |
Level 3 | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (13 | ) | | $ | (10 | ) | | $ | (3 | ) | $ | (13 | ) | | $ | (7 | ) | | $ | (6 | ) |
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related and interest rate derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 11 to the financial statements.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to total $2.5$3.3 billion for 2016,2018, $3.2 billion for 2019, $2.7 billion for 2020, $2.4 billion for 2017,2021, and $2.1$2.2 billion for 2018.2022. These amounts include expenditures of approximately $0.6$1.2 billion, $1.0 billion, $0.9 billion, $0.7 billion, and $0.4 billion to continuefor the construction onof Plant Vogtle Units 3 and 4 in 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.LTSAs. Estimated capital expenditures to comply with environmental statuteslaws and regulations included in these amounts are $0.3$0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA's final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-firedfossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure in place or by other methods, and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.2 billion $0.2per year for 2018 through 2020 and $0.3 billion per year for 2021 and $0.1 billion for the years 2016, 2017, and 2018, respectively.2022. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which may be subject to revised cost estimates during construction. The ability to control costs and avoid cost overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
will be fully recovered.training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements under "Retail Regulatory Matters – Nuclear Construction" for information regarding additional factors that may impact construction expenditures.
As a result of requirements by the NRC, the Company has established external trust funds for nuclear decommissioning costs. For additional information, see Note 1 to the financial statements under "Nuclear Decommissioning."
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, other purchase commitments, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 2, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 704 |
| | $ | 1,197 |
| | $ | 539 |
| | $ | 7,833 |
| | $ | 10,273 |
|
Interest | 382 |
| | 715 |
| | 617 |
| | 5,205 |
| | 6,919 |
|
Preferred and preference stock dividends(b) | 17 |
| | 35 |
| | 35 |
| | — |
| | 87 |
|
Financial derivative obligations(c) | 12 |
| | 3 |
| | — |
| | — |
| | 15 |
|
Operating leases(d) | 23 |
| | 30 |
| | 15 |
| | 16 |
| | 84 |
|
Capital leases(d) | 6 |
| | 14 |
| | 15 |
| | — |
| | 35 |
|
Purchase commitments — | | | | | | | | | |
Capital(e) | 2,385 |
| | 4,113 |
| | — |
| | — |
| | 6,498 |
|
Fuel(f) | 1,423 |
| | 1,789 |
| | 879 |
| | 6,635 |
| | 10,726 |
|
Purchased power(g) | 337 |
| | 633 |
| | 544 |
| | 2,803 |
| | 4,317 |
|
Other(h) | 66 |
| | 144 |
| | 148 |
| | 170 |
| | 528 |
|
Trusts — | | | | | | | | | |
Nuclear decommissioning(i) | 5 |
| | 11 |
| | 11 |
| | 104 |
| | 131 |
|
Pension and other postretirement benefit plans(j) | 42 |
| | 78 |
| | — |
| | — |
| | 120 |
|
Total | $ | 5,402 |
| | $ | 8,762 |
| | $ | 2,803 |
| | $ | 22,766 |
| | $ | 39,733 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 850 |
| | $ | 1,494 |
| | $ | 879 |
| | $ | 8,693 |
| | $ | 11,916 |
|
Interest | 419 |
| | 760 |
| | 688 |
| | 5,786 |
| | 7,653 |
|
Financial derivative obligations(b) | 10 |
| | 10 |
| | — |
| | — |
| | 20 |
|
Operating leases(c) | 24 |
| | 42 |
| | 31 |
| | 44 |
| | 141 |
|
Capital leases(c) | 9 |
| | 16 |
| | — |
| | — |
| | 25 |
|
Purchase commitments — | | | | | | | | | |
Capital(d) | 3,080 |
| | 5,508 |
| | 4,006 |
| | — |
| | 12,594 |
|
Fuel(e) | 1,238 |
| | 1,245 |
| | 818 |
| | 5,075 |
| | 8,376 |
|
Purchased power(f) | 318 |
| | 545 |
| | 549 |
| | 2,352 |
| | 3,764 |
|
Other(g) | 50 |
| | 198 |
| | 70 |
| | 297 |
| | 615 |
|
Trusts — | | | | | | | | | |
Nuclear decommissioning(h) | 5 |
| | 11 |
| | 11 |
| | 94 |
| | 121 |
|
Pension and other postretirement benefit plans(i) | 47 |
| | 87 |
| | | | | | 134 |
|
Total | $ | 6,050 |
| | $ | 9,916 |
| | $ | 7,052 |
| | $ | 22,341 |
| | $ | 45,359 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 6 to the financial statements under "DOE Loan Guarantee Borrowings" for additional information. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2016,December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). |
| |
(b) | Preferred and preference stock do not mature; therefore, amounts provided are for the next five years only. |
| |
(c) | Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, seeSee Notes 1 and 11 to the financial statements. |
| |
(d)(c) | Excludes PPAs that are accounted for as leases and included in "Purchased power." See Note 7 to the financial statements under "Operating Leases" for additional information. |
| |
(e)(d) | The Company provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreementsLTSAs which are reflected in "Fuel" and "Other," respectively. At December 31, 2015,2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and "Retail Regulatory Matters – Nuclear Construction" herein for additional information. |
| |
(f)(e) | Includes commitments to purchase coal, nuclear fuel, and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(g)(f) | Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities. Includes a total of $304 million of biomass PPAs that is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables Development" herein for additional information. |
| |
(h)(g) | Includes long-term service agreementsLTSAs and contracts for the procurement of limestone. Long-term service agreementsLTSAs include price escalation based on inflation indices. |
| |
(i)(h) | Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP. See Note 1 to the financial statements under "Nuclear Decommissioning" for additional information. |
| |
(j)(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retailregulated rates, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, and changing fuel sources, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development, construction, and constructionoperation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Georgia PSC);performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Company's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate cases related to fuel and other cost recovery mechanisms;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;actions;
the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Georgia Power Company 20152017 Annual Report
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Georgia Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Retail revenues | $ | 7,727 |
| | $ | 8,240 |
| | $ | 7,620 |
| $ | 7,738 |
| | $ | 7,772 |
| | $ | 7,727 |
|
Wholesale revenues, non-affiliates | 215 |
| | 335 |
| | 281 |
| 163 |
| | 175 |
| | 215 |
|
Wholesale revenues, affiliates | 20 |
| | 42 |
| | 20 |
| 26 |
| | 42 |
| | 20 |
|
Other revenues | 364 |
| | 371 |
| | 353 |
| 383 |
| | 394 |
| | 364 |
|
Total operating revenues | 8,326 |
| | 8,988 |
| | 8,274 |
| 8,310 |
| | 8,383 |
| | 8,326 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 2,033 |
| | 2,547 |
| | 2,307 |
| 1,671 |
| | 1,807 |
| | 2,033 |
|
Purchased power, non-affiliates | 289 |
| | 287 |
| | 224 |
| 416 |
| | 361 |
| | 289 |
|
Purchased power, affiliates | 575 |
| | 701 |
| | 660 |
| 622 |
| | 518 |
| | 575 |
|
Other operations and maintenance | 1,844 |
| | 1,902 |
| | 1,654 |
| 1,653 |
| | 1,960 |
| | 1,844 |
|
Depreciation and amortization | 846 |
| | 846 |
| | 807 |
| 895 |
| | 855 |
| | 846 |
|
Taxes other than income taxes | 391 |
| | 409 |
| | 382 |
| 409 |
| | 405 |
| | 391 |
|
Total operating expenses | 5,978 |
| | 6,692 |
| | 6,034 |
| 5,666 |
| | 5,906 |
| | 5,978 |
|
Operating Income | 2,348 |
| | 2,296 |
| | 2,240 |
| 2,644 |
| | 2,477 |
| | 2,348 |
|
Other Income and (Expense): | | | | | | | | | | |
Interest expense, net of amounts capitalized | (363 | ) | | (348 | ) | | (361 | ) | (419 | ) | | (388 | ) | | (363 | ) |
Other income (expense), net | 61 |
| | 23 |
| | 35 |
| 33 |
| | 38 |
| | 61 |
|
Total other income and (expense) | (302 | ) | | (325 | ) | | (326 | ) | (386 | ) | | (350 | ) | | (302 | ) |
Earnings Before Income Taxes | 2,046 |
| | 1,971 |
| | 1,914 |
| 2,258 |
| | 2,127 |
| | 2,046 |
|
Income taxes | 769 |
| | 729 |
| | 723 |
| 830 |
| | 780 |
| | 769 |
|
Net Income | 1,277 |
| | 1,242 |
| | 1,191 |
| 1,428 |
| | 1,347 |
| | 1,277 |
|
Dividends on Preferred and Preference Stock | 17 |
| | 17 |
| | 17 |
| 14 |
| | 17 |
| | 17 |
|
Net Income After Dividends on Preferred and Preference Stock | $ | 1,260 |
| | $ | 1,225 |
| | $ | 1,174 |
| $ | 1,414 |
| | $ | 1,330 |
| | $ | 1,260 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Georgia Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Net Income | $ | 1,277 |
| | $ | 1,242 |
| | $ | 1,191 |
| $ | 1,428 |
| | $ | 1,347 |
| | $ | 1,277 |
|
Other comprehensive income (loss): | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $(6), $(3), and $-, respectively | (9 | ) | | (5 | ) | | — |
| |
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 2 |
| | 2 |
| | 2 |
| |
Changes in fair value, net of tax of $-, $-, and $(6), respectively | | — |
| | — |
| | (9 | ) |
Reclassification adjustment for amounts included in net income, net of tax of $1, $2, and $1, respectively | | 3 |
| | 2 |
| | 2 |
|
Total other comprehensive income (loss) | (7 | ) | | (3 | ) | | 2 |
| 3 |
| | 2 |
| | (7 | ) |
Comprehensive Income | $ | 1,270 |
| | $ | 1,239 |
| | $ | 1,193 |
| $ | 1,431 |
| | $ | 1,349 |
| | $ | 1,270 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Georgia Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Activities: | | | | | | | | | | |
Net income | $ | 1,277 |
| | $ | 1,242 |
| | $ | 1,191 |
| $ | 1,428 |
| | $ | 1,347 |
| | $ | 1,277 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization, total | 1,029 |
| | 1,019 |
| | 979 |
| 1,100 |
| | 1,063 |
| | 1,029 |
|
Deferred income taxes | 173 |
| | 352 |
| | 476 |
| 458 |
| | 383 |
| | 173 |
|
Allowance for equity funds used during construction | (40 | ) | | (45 | ) | | (30 | ) | |
Retail fuel cost over-recovery — long-term | 106 |
| | (44 | ) | | (123 | ) | |
Retail fuel cost over recovery — long-term | | — |
| | — |
| | 106 |
|
Pension, postretirement, and other employee benefits | 40 |
| | 19 |
| | 66 |
| (68 | ) | | (33 | ) | | 40 |
|
Pension and postretirement funding | (7 | ) | | (156 | ) | | (8 | ) | — |
| | (287 | ) | | (7 | ) |
Settlement of asset retirement obligations | | (120 | ) | | (123 | ) | | (29 | ) |
Other deferred charges — affiliated | | — |
| | (111 | ) | | — |
|
Other, net | (59 | ) | | 39 |
| | 38 |
| (83 | ) | | (25 | ) | | (70 | ) |
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | 187 |
| | (248 | ) | | (58 | ) | (256 | ) | | 60 |
| | 187 |
|
-Fossil fuel stock | 37 |
| | 303 |
| | 250 |
| (16 | ) | | 104 |
| | 37 |
|
-Prepaid income taxes | 89 |
| | (216 | ) | | (17 | ) | (168 | ) | | — |
| | 89 |
|
-Other current assets | (62 | ) | | (37 | ) | | 40 |
| (28 | ) | | (38 | ) | | (62 | ) |
-Accounts payable | (259 | ) | | 16 |
| | 67 |
| (219 | ) | | (42 | ) | | (259 | ) |
-Accrued taxes | 25 |
| | 17 |
| | (14 | ) | 1 |
| | 131 |
| | 25 |
|
-Accrued compensation | (17 | ) | | 62 |
| | (37 | ) | |
-Retail fuel cost over-recovery — short-term | 10 |
| | (14 | ) | | (49 | ) | |
-Retail fuel cost over recovery | | (84 | ) | | (32 | ) | | 10 |
|
-Other current liabilities | (12 | ) | | 54 |
| | (5 | ) | (33 | ) | | 28 |
| | (29 | ) |
Net cash provided from operating activities | 2,517 |
| | 2,363 |
| | 2,766 |
| 1,912 |
| | 2,425 |
| | 2,517 |
|
Investing Activities: | | | | | | | | | | |
Property additions | (2,091 | ) | | (2,023 | ) | | (1,743 | ) | (2,704 | ) | | (2,223 | ) | | (2,091 | ) |
Investment in restricted cash from pollution control bonds | — |
| | — |
| | (89 | ) | |
Distribution of restricted cash from pollution control bonds | — |
| | — |
| | 89 |
| |
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion | | 1,682 |
| | — |
| | — |
|
Nuclear decommissioning trust fund purchases | (985 | ) | | (671 | ) | | (706 | ) | (574 | ) | | (808 | ) | | (985 | ) |
Nuclear decommissioning trust fund sales | 980 |
| | 669 |
| | 705 |
| 568 |
| | 803 |
| | 980 |
|
Cost of removal, net of salvage | (71 | ) | | (65 | ) | | (59 | ) | (100 | ) | | (83 | ) | | (71 | ) |
Change in construction payables, net of joint owner portion | 217 |
| | (54 | ) | | (67 | ) | 223 |
| | (35 | ) | | 217 |
|
Prepaid long-term service agreements | (66 | ) | | (70 | ) | | (18 | ) | |
Payments pursuant to LTSAs | | (64 | ) | | (34 | ) | | (66 | ) |
Sale of property | 70 |
| | 7 |
| | 7 |
| 96 |
| | 10 |
| | 70 |
|
Other investing activities | 2 |
| | 1 |
| | (9 | ) | (39 | ) | | 23 |
| | 2 |
|
Net cash used for investing activities | (1,944 | ) | | (2,206 | ) | | (1,890 | ) | (912 | ) | | (2,347 | ) | | (1,944 | ) |
Financing Activities: | | | | | | | | | | |
Increase (decrease) in notes payable, net | 2 |
| | (891 | ) | | 1,047 |
| (391 | ) | | 234 |
| | 2 |
|
Proceeds — | | | | | | | | | | |
Senior notes | | 1,350 |
| | 650 |
| | 500 |
|
FFB loan | | — |
| | 425 |
| | 1,000 |
|
Pollution control revenue bonds issuances and remarketings | | 65 |
| | — |
| | 409 |
|
Capital contributions from parent company | 62 |
| | 549 |
| | 37 |
| 431 |
| | 594 |
| | 62 |
|
Pollution control revenue bonds issuances and remarketings | 409 |
| | 40 |
| | 194 |
| |
Senior notes issuances | 500 |
| | — |
| | 850 |
| |
FFB loan | 1,000 |
| | 1,200 |
| | — |
| |
Short-term borrowings | 250 |
| | — |
| | — |
| 700 |
| | — |
| | 250 |
|
Other long-term debt | | 370 |
| | — |
| | — |
|
Redemptions and repurchases — | | | | | | | | | | |
Senior notes | | (450 | ) | | (700 | ) | | (1,175 | ) |
Preferred and preference stock | | (270 | ) | | — |
| | — |
|
Pollution control revenue bonds | (268 | ) | | (37 | ) | | (298 | ) | (65 | ) | | (4 | ) | | (268 | ) |
Senior notes | (1,175 | ) | | — |
| | (1,775 | ) | |
Short-term borrowings | (250 | ) | | — |
| | — |
| (550 | ) | | — |
| | (250 | ) |
Payment of preferred and preference stock dividends | (17 | ) | | (17 | ) | | (17 | ) | |
Payment of common stock dividends | (1,034 | ) | | (954 | ) | | (907 | ) | (1,281 | ) | | (1,305 | ) | | (1,034 | ) |
FFB loan issuance costs | — |
| | (49 | ) | | (5 | ) | |
Other financing activities | (9 | ) | | (4 | ) | | (17 | ) | (60 | ) | | (36 | ) | | (26 | ) |
Net cash used for financing activities | (530 | ) | | (163 | ) | | (891 | ) | (151 | ) | | (142 | ) | | (530 | ) |
Net Change in Cash and Cash Equivalents | 43 |
| | (6 | ) | | (15 | ) | 849 |
| | (64 | ) | | 43 |
|
Cash and Cash Equivalents at Beginning of Year | 24 |
| | 30 |
| | 45 |
| 3 |
| | 67 |
| | 24 |
|
Cash and Cash Equivalents at End of Year | $ | 67 |
| | $ | 24 |
| | $ | 30 |
| $ | 852 |
| | $ | 3 |
| | $ | 67 |
|
Supplemental Cash Flow Information: | | | | | | | | | | |
Cash paid during the period for — | | | | | | | | | | |
Interest (net of $16, $18, and $14 capitalized, respectively) | $ | 353 |
| | $ | 319 |
| | $ | 344 |
| |
Interest (net of $23, $20, and $16 capitalized, respectively) | | $ | 386 |
| | $ | 375 |
| | $ | 353 |
|
Income taxes (net of refunds) | 506 |
| | 507 |
| | 298 |
| 496 |
| | 170 |
| | 506 |
|
Noncash transactions — | | | | | | | | | | |
Accrued property additions at year-end | 387 |
| | 154 |
| | 208 |
| 550 |
| | 336 |
| | 387 |
|
Capital lease obligation | 149 |
| | — |
| | — |
| — |
| | — |
| | 149 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Georgia Power Company 20152017 Annual Report
| | Assets | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 67 |
| | $ | 24 |
| $ | 852 |
| | $ | 3 |
|
Receivables — | | | | | | |
Customer accounts receivable | 541 |
| | 553 |
| 708 |
| | 523 |
|
Unbilled revenues | 188 |
| | 201 |
| 255 |
| | 224 |
|
Joint owner accounts receivable | 227 |
| | 121 |
| 262 |
| | 57 |
|
Affiliated | | 24 |
| | 18 |
|
Other accounts and notes receivable | 57 |
| | 61 |
| 76 |
| | 81 |
|
Affiliated companies | 18 |
| | 18 |
| |
Accumulated provision for uncollectible accounts | (2 | ) | | (6 | ) | (3 | ) | | (3 | ) |
Income taxes receivable, current | 114 |
| | — |
| |
Fossil fuel stock, at average cost | 402 |
| | 439 |
| |
Materials and supplies, at average cost | 449 |
| | 438 |
| |
Vacation pay | 91 |
| | 91 |
| |
Prepaid income taxes | 156 |
| | 244 |
| |
Fossil fuel stock | | 314 |
| | 298 |
|
Materials and supplies | | 504 |
| | 479 |
|
Prepaid expenses | | 216 |
| | 105 |
|
Other regulatory assets, current | 123 |
| | 136 |
| 205 |
| | 193 |
|
Other current assets | 92 |
| | 74 |
| 15 |
| | 38 |
|
Total current assets | 2,523 |
| | 2,394 |
| 3,428 |
| | 2,016 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 31,841 |
| | 31,083 |
| 34,861 |
| | 33,841 |
|
Less accumulated provision for depreciation | 10,903 |
| | 11,222 |
| |
Less: Accumulated provision for depreciation | | 11,704 |
| | 11,317 |
|
Plant in service, net of depreciation | 20,938 |
| | 19,861 |
| 23,157 |
| | 22,524 |
|
Other utility plant, net | 171 |
| | 211 |
| |
Nuclear fuel, at amortized cost | 572 |
| | 563 |
| 544 |
| | 569 |
|
Construction work in progress | 4,775 |
| | 4,031 |
| 4,613 |
| | 4,939 |
|
Total property, plant, and equipment | 26,456 |
| | 24,666 |
| 28,314 |
| | 28,032 |
|
Other Property and Investments: | | | | | | |
Equity investments in unconsolidated subsidiaries | 64 |
| | 58 |
| 53 |
| | 60 |
|
Nuclear decommissioning trusts, at fair value | 775 |
| | 789 |
| 929 |
| | 814 |
|
Miscellaneous property and investments | 43 |
| | 38 |
| 59 |
| | 46 |
|
Total other property and investments | 882 |
| | 885 |
| 1,041 |
| | 920 |
|
Deferred Charges and Other Assets: | | | | | | |
Deferred charges related to income taxes | 679 |
| | 698 |
| 516 |
| | 676 |
|
Deferred under recovered regulatory clause revenues | — |
| | 197 |
| |
Other regulatory assets, deferred | 2,152 |
| | 1,753 |
| 2,932 |
| | 2,774 |
|
Other deferred charges and assets | 173 |
| | 279 |
| 548 |
| | 417 |
|
Total deferred charges and other assets | 3,004 |
| | 2,927 |
| 3,996 |
| | 3,867 |
|
Total Assets | $ | 32,865 |
| | $ | 30,872 |
| $ | 36,779 |
| | $ | 34,835 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Georgia Power Company 20152017 Annual Report
| | Liabilities and Stockholder's Equity | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Liabilities: | | | | | | |
Securities due within one year | $ | 712 |
| | $ | 1,150 |
| $ | 857 |
| | $ | 460 |
|
Notes payable | 158 |
| | 156 |
| 150 |
| | 391 |
|
Accounts payable — | | | | | | |
Affiliated | 411 |
| | 451 |
| 493 |
| | 438 |
|
Other | 750 |
| | 555 |
| 834 |
| | 589 |
|
Customer deposits | 264 |
| | 253 |
| 270 |
| | 265 |
|
Accrued taxes — | | | | | | |
Accrued income taxes | 12 |
| | — |
| — |
| | 17 |
|
Other accrued taxes | 325 |
| | 332 |
| 344 |
| | 390 |
|
Accrued interest | 99 |
| | 96 |
| 123 |
| | 106 |
|
Accrued vacation pay | 62 |
| | 63 |
| |
Accrued compensation | 142 |
| | 153 |
| 219 |
| | 224 |
|
Asset retirement obligations, current | 179 |
| | 32 |
| 270 |
| | 299 |
|
Liabilities from risk management activities | 12 |
| | 32 |
| |
Other regulatory liabilities, current | 16 |
| | 21 |
| 191 |
| | 31 |
|
Over recovered regulatory clause revenues, current | 10 |
| | — |
| |
Over recovered fuel clause revenues, current | | — |
| | 84 |
|
Other current liabilities | 143 |
| | 172 |
| 198 |
| | 182 |
|
Total current liabilities | 3,295 |
| | 3,466 |
| 3,949 |
| | 3,476 |
|
Long-Term Debt (See accompanying statements) | 9,616 |
| | 8,563 |
| 11,073 |
| | 10,225 |
|
Deferred Credits and Other Liabilities: | | | | | | |
Accumulated deferred income taxes | 5,627 |
| | 5,474 |
| 3,175 |
| | 6,000 |
|
Deferred credits related to income taxes | 105 |
| | 106 |
| 3,248 |
| | 121 |
|
Accumulated deferred investment tax credits | 204 |
| | 196 |
| |
Accumulated deferred ITCs | | 248 |
| | 256 |
|
Employee benefit obligations | 949 |
| | 903 |
| 659 |
| | 703 |
|
Asset retirement obligations, deferred | 1,737 |
| | 1,223 |
| 2,368 |
| | 2,233 |
|
Other cost of removal obligations | 16 |
| | 46 |
| |
Other deferred credits and liabilities | 331 |
| | 208 |
| 128 |
| | 199 |
|
Total deferred credits and other liabilities | 8,969 |
| | 8,156 |
| 9,826 |
| | 9,512 |
|
Total Liabilities | 21,880 |
| | 20,185 |
| 24,848 |
| | 23,213 |
|
Preferred Stock (See accompanying statements) | 45 |
| | 45 |
| — |
| | 45 |
|
Preference Stock (See accompanying statements) | 221 |
| | 221 |
| — |
| | 221 |
|
Common Stockholder's Equity (See accompanying statements) | 10,719 |
| | 10,421 |
| 11,931 |
| | 11,356 |
|
Total Liabilities and Stockholder's Equity | $ | 32,865 |
| | $ | 30,872 |
| $ | 36,779 |
| | $ | 34,835 |
|
Commitments and Contingent Matters (See notes) |
| |
|
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 20152017 and 20142016
Georgia Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) | (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | | | | | | | | |
Long-term notes payable — | | | | | | | | | | | | | | |
Variable rates (0.76% to 0.83% at 1/1/16) due 2016 | $ | 450 |
| | $ | 450 |
| | | | | |
0.625% to 5.25% due 2015 | — |
| | 1,050 |
| | | | | |
3.00% due 2016 | 250 |
| | 250 |
| | | | | |
5.70% due 2017 | 450 |
| | 450 |
| | | | | $ | — |
| | $ | 450 |
| | | | |
1.95% to 5.40% due 2018 | 747 |
| | 250 |
| | | | | 747 |
| | 748 |
| | | | |
4.25% due 2019 | 502 |
| | 500 |
| | | | | 499 |
| | 500 |
| | | | |
2.85% to 5.95% due 2022-2043 | 3,850 |
| | 3,975 |
| | | | | |
2.00% due 2020 | | 950 |
| | — |
| | | | |
2.40% due 2021 | | 325 |
| | 325 |
| | | | |
2.85% due 2022 | | 400 |
| | 400 |
| | | | |
3.25% to 5.95% due 2023-2043 | | 4,175 |
| | 3,775 |
| | | | |
Variable rate (2.29% at 12/31/17) due 2018 | | 100 |
| | — |
| | | | |
Total long-term notes payable | 6,249 |
| | 6,925 |
| | | | | 7,196 |
| | 6,198 |
| | | | |
Other long-term debt — | | | | | | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | | | | | | |
0.85% to 4.00% due 2022-2049 | 952 |
| | 818 |
| | | | | |
Variable rates (0.03% to 0.04% at 1/1/15) due 2015 | — |
| | 98 |
| | | | | |
Variable rate (0.22% at 1/1/16) due 2016 | 4 |
| | 4 |
| | | | | |
Variable rates (0.10% to 0.27% at 1/1/16) due 2022-2053 | 868 |
| | 763 |
| | | | | |
2.35% due 2022 | | 53 |
| | 53 |
| | | | |
1.38% to 4.00% due 2025-2049 | | 940 |
| | 900 |
| | | | |
Variable rate (1.84% at 12/31/17) due 2022 | | 13 |
| | 13 |
| | | | |
Variable rates (1.59% to 1.88% at 12/31/17) due 2026-2053 | | 815 |
| | 854 |
| | | | |
FFB loans — | | | | | | | | | | | | | | |
3.00% to 3.86% due 2020 | 37 |
| | 20 |
| | | | | |
3.00% to 3.86% due 2021-2044 | 2,163 |
| | 1,180 |
| | | | | |
2.57% to 3.86% due 2020 | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2021 | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2022 | | 44 |
| | 44 |
| | | | |
2.57% to 3.86% due 2023-2044 | | 2,493 |
| | 2,493 |
| | | | |
Junior subordinated note (5.00%) due 2077 | | 270 |
| | — |
| | | | |
Total other long-term debt | 4,024 |
| | 2,883 |
| | | | | 4,716 |
| | 4,445 |
| | | | |
Capitalized lease obligations | 183 |
| | 40 |
| | | | | 154 |
| | 169 |
| | | | |
Unamortized debt premium (discount), net | (10 | ) | | (11 | ) | | | | | (12 | ) | | (10 | ) | | | | |
Unamortized debt issuance expense | (118 | ) | | (124 | ) | | | | | (124 | ) | | (117 | ) | | | | |
Total long-term debt (annual interest requirement — $382 million) | 10,328 |
| | 9,713 |
| | | | | |
Total long-term debt (annual interest requirement — $437 million) | | 11,930 |
| | 10,685 |
| | | | |
Less amount due within one year | 712 |
| | 1,150 |
| | | | | 857 |
| | 460 |
| | | | |
Long-term debt excluding amount due within one year | 9,616 |
| | 8,563 |
| | 46.7 | % | | 44.5 | % | 11,073 |
| | 10,225 |
| | 48.1 | % | | 46.8 | % |
Preferred and Preference Stock: | | | | | | | | | | | | | | |
Non-cumulative preferred stock | | | | | | | | | | | | | | |
$25 par value — 6.125% | | | | | | | | | | | | | | |
Authorized — 50,000,000 shares | | | | | | | | | | | | | | |
Outstanding — 1,800,000 shares | 45 |
| | 45 |
| | | | | |
Outstanding — 2017: no shares | | | | | | | | |
— 2016: 1,800,000 shares | | — |
| | 45 |
| | | | |
Non-cumulative preference stock | | | | | | | | | | | | | | |
$100 par value — 6.50% | | | | | | | | | | | | | | |
Authorized — 15,000,000 shares | | | | | | | | | | | | | | |
Outstanding — 2,250,000 shares | 221 |
| | 221 |
| | | | | |
Total preferred and preference stock (annual dividend requirement — $17 million) | 266 |
| | 266 |
| | 1.3 |
| | 1.4 |
| |
Outstanding — 2017: no shares | | | | | | | | |
— 2016: 2,250,000 shares | | — |
| | 221 |
| | | | |
Total preferred and preference stock | | — |
| | 266 |
| | — |
| | 1.2 |
|
Common Stockholder's Equity: | | | | | | | | | | | | | | |
Common stock, without par value — | | | | | | | | | | | | | | |
Authorized — 20,000,000 shares |
| |
| | | | | | | | | | | |
Outstanding — 9,261,500 shares | 398 |
| | 398 |
| | | | | 398 |
| | 398 |
| | | | |
Paid-in capital | 6,275 |
| | 6,196 |
| | | | | 7,328 |
| | 6,885 |
| | | | |
Retained earnings | 4,061 |
| | 3,835 |
| | | | | 4,215 |
| | 4,086 |
| | | | |
Accumulated other comprehensive loss | (15 | ) | | (8 | ) | | | | | (10 | ) | | (13 | ) | | | | |
Total common stockholder's equity | 10,719 |
| | 10,421 |
| | 52.0 |
| | 54.1 |
| 11,931 |
| | 11,356 |
| | 51.9 |
| | 52.0 |
|
Total Capitalization | $ | 20,601 |
| | $ | 19,250 |
| | 100.0 | % | | 100.0 | % | $ | 23,004 |
| | $ | 21,847 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2015, 2014,2017, 2016, and 20132015
Georgia Power Company 20152017 Annual Report
| | | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) | (in millions) |
Balance at December 31, 2012 | 9 |
| | $ | 398 |
| | $ | 5,585 |
| | $ | 3,297 |
| | $ | (7 | ) | | $ | 9,273 |
| |
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 1,174 |
| | — |
| | 1,174 |
| |
Capital contributions from parent company | — |
| | — |
| | 48 |
| | — |
| | — |
| | 48 |
| |
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (907 | ) | | — |
| | (907 | ) | |
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| |
Balance at December 31, 2013 | 9 |
| | 398 |
| | 5,633 |
| | 3,565 |
| | (5 | ) | | 9,591 |
| |
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 1,225 |
| | — |
| | 1,225 |
| |
Capital contributions from parent company | — |
| | — |
| | 563 |
| | — |
| | — |
| | 563 |
| |
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (3 | ) | | (3 | ) | |
Cash dividends on common stock | — |
| | — |
| | — |
| | (954 | ) | | — |
| | (954 | ) | |
Other | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) | |
Balance at December 31, 2014 | 9 |
| | 398 |
| | 6,196 |
| | 3,835 |
| | (8 | ) | | 10,421 |
| 9 |
| | $ | 398 |
| | $ | 6,196 |
| | $ | 3,835 |
| | $ | (8 | ) | | $ | 10,421 |
|
Net income after dividends on preferred and preference stock | — |
| | — |
| | — |
| | 1,260 |
| | — |
| | 1,260 |
| — |
| | — |
| | — |
| | 1,260 |
| | — |
| | 1,260 |
|
Capital contributions from parent company | — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
| — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | (7 | ) | | (7 | ) | — |
| | — |
| | — |
| | — |
| | (7 | ) | | (7 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (1,034 | ) | | — |
| | (1,034 | ) | — |
| | — |
| | — |
| | (1,034 | ) | | — |
| | (1,034 | ) |
Balance at December 31, 2015 | 9 |
| | $ | 398 |
| | $ | 6,275 |
| | $ | 4,061 |
| | $ | (15 | ) | | $ | 10,719 |
| 9 |
| | 398 |
| | 6,275 |
| | 4,061 |
| | (15 | ) | | 10,719 |
|
Net income after dividends on preferred and preference stock | | — |
| | — |
| | — |
| | 1,330 |
| | — |
| | 1,330 |
|
Capital contributions from parent company | | — |
| | — |
| | 610 |
| | — |
| | — |
| | 610 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Cash dividends on common stock | | — |
| | — |
| | — |
| | (1,305 | ) | | — |
| | (1,305 | ) |
Balance at December 31, 2016 | | 9 |
| | 398 |
| | 6,885 |
| | 4,086 |
| | (13 | ) | | 11,356 |
|
Net income after dividends on preferred and preference stock | | — |
| | — |
| | — |
| | 1,414 |
| | — |
| | 1,414 |
|
Capital contributions from parent company | | — |
| | — |
| | 443 |
| | — |
| | — |
| | 443 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Cash dividends on common stock | | — |
| | — |
| | — |
| | (1,281 | ) | | — |
| | (1,281 | ) |
Other | | — |
| | — |
| | — |
| | (4 | ) | | — |
| | (4 | ) |
Balance at December 31, 2017 | | 9 |
| | $ | 398 |
| | $ | 7,328 |
| | $ | 4,215 |
| | $ | (10 | ) | | $ | 11,931 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Georgia Power Company 20152017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Georgia Power Company 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Georgia Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, SouthernLINC Wireless,Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricityelectric service to retail customers within its traditional service areaterritory located within the State of Georgia and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cableoptics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle.Vogtle Units 1 and 2, and is managing construction of Plant Vogtle Units 3 and 4. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The equity method is used for subsidiaries in which the Company has significant influence but does not control.
The Company is subject to regulation by the FERC and the Georgia PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
In June 2015, the Company identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, the Company recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. The Company evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period.error. Based on an analysis of qualitative and quantitative factors, the Company determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers(ASC 606), revisesreplacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. The Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of ASC 606. The ultimate impactadoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the new standard has not yet been determined.
On April 7, 2015,transaction price for contracts modified before the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $124 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Notes 6 and 10 for disclosures impacted by ASU 2015-03.date. Under
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Company. See Notes 2 and 10 forthe modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures impacted by ASU 2015-07.will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
On November 20, 2015,In February 2016, the FASB issued ASU No. 2015-17,2016-02, Income TaxesLeases (Topic 740): Balance Sheet Classification of Deferred Taxes 842)( (ASU 2016-02). ASU 2015-17), which simplifies2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of deferred income taxes.expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to PPAs and cellular towers where the Company is the lessee and to outdoor lighting where the Company is the lessor. The Company is currently analyzing pole attachment agreements, and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, including interim periods within that reporting period. As permitted, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to early adopt the guidance in 2016 and reflect the related adjustments as of December 31, 2015 and applied its provisions retrospectivelyJanuary 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts.recognize forfeitures as they occur. The new guidance resulted in a reclassification from prepaid income taxes of $34 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have ana material impact on the results of operations, financial position, or cash flows or financial condition of the Company. See NoteNotes 5 and 8 for disclosures impacted by ASU 2015-17.2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
NOTES (continued)
Georgia Power Company 2017 Annual Report
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $625 million, $606 million, and $585 million in 2017, 2016, and 2015, $555 million in 2014, and $504 million in 2013.respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment.
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services,services; general operations, management, and technical services,services; administrative services including procurement, accounting, employee relations, systems, and procedures services,services; strategic planning and budgeting services,services; and other services with respect to business, operations, and construction management. Costs for these services amounted to $675 million, $666 million, and $681 million in 2017, 2016, and 2015, $643 million in 2014, and $555 million in 2013.respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information.
The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $235 million, $265 million, and $179 million $144 million,in 2017, 2016, and $136 million in 2015, 2014,respectively. See Note 6 under "Capital Leases" and 2013, respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2015 and 2014. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $11 million, $8 million, and $12 million in 2017, 2016, and 2015, $9 million in 2014, and $10 million in 2013.respectively. See Note 4 for additional information.
In 2014, prior to Southern Company's acquisition of PowerSecure on May 9, 2016, the Company entered into agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. In October 2016, the two facilities began commercial operation. Payments of $119 million made by the Company to PowerSecure under the agreements since 2014 are included in utility plant in service at December 31, 2017.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $102 million in 2017 and $35 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $22 million in 2017 and $10 million for the period subsequent to Southern Company's acquisition of Southern Company Gas through December 31, 2016.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015, 2014,2017, 2016, or 2013.2015.
The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of the FASB in accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
| | | 2015 |
| | 2014 |
| | Note | 2017 | | 2016 | | Note |
| (in millions) | | (in millions) | |
Retiree benefit plans | $ | 1,307 |
| | $ | 1,325 |
| | (a, j) | $ | 1,313 |
| | $ | 1,348 |
| | (a, k) |
Asset retirement obligations | | 945 |
| | 893 |
| | (b, k) |
Deferred income tax charges | 653 |
| | 668 |
| | (b, j) | 521 |
| | 681 |
| | (b, c, k) |
Storm damage reserves | | 333 |
| | 206 |
| | (d) |
Remaining net book value of retired assets | | 146 |
| | 166 |
| | (e) |
Loss on reacquired debt | 150 |
| | 163 |
| | (c, j) | 127 |
| | 137 |
| | (f, k) |
Asset retirement obligations | 411 |
| | 108 |
| | (b, j) | |
Other regulatory assets | | 119 |
| | 97 |
| | (g) |
Vacation pay | 91 |
| | 91 |
| | (d, j) | 91 |
| | 91 |
| | (h, k) |
Other cost of removal obligations | | 40 |
| | 3 |
| | (b) |
Cancelled construction projects | 56 |
| | 67 |
| | (e) | 36 |
| | 44 |
| | (i) |
Remaining net book value of retired assets | 171 |
| | 29 |
| | (f) | |
Storm damage reserves | 92 |
| | 98 |
| | (g) | |
Other regulatory assets | 140 |
| | 153 |
| | (h) | |
Other cost of removal obligations | (31 | ) | | (60 | ) | | (b) | |
Deferred income tax credits | (105 | ) | | (106 | ) | | (b, j) | (3,248 | ) | | (121 | ) | | (b, c) |
Other regulatory liabilities | (2 | ) | | (7 | ) | | (i, j) | (191 | ) | | (39 | ) | | (j, k) |
Total regulatory assets (liabilities), net | $ | 2,933 |
| | $ | 2,529 |
| | $ | 232 |
| | $ | 3,506 |
| |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. |
| |
(b) | Asset retirement and other cost of removal obligations and deferred income tax assets are recovered and deferred income tax liabilities are amortized over the related property lives, which may range up to 7065 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2015, other cost of removal obligations included $14 million that will be amortized over the twelve months ending December 31, 2016 in accordance with the three-year amortization period approvedIncluded in the Company's 2013 ARP.deferred income tax assets is $21 million for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Georgia PSC, through 2022. |
| |
(c) | As a result of Tax Reform Legislation, these balances include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and $626 million of deferred income tax liabilities, neither of which are subject to normalization. The recovery and amortization of these amounts will be determined by the Georgia PSC. See Note 3 under "Retail Regulatory Matters – Rate Plans" and Note 5 for additional information. |
| |
(d) | Previous under-recovery as of December 2013 is recorded and recovered or amortized as approved by the Georgia PSC through 2019. Amortization of $319 million related to the under-recovery from January 2014 through December 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information. |
| |
(e) | Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2024. The net book value of Plant Mitchell Unit 3 at December 31, 2017 was $10 million, which will continue to be amortized through December 31, 2019 as provided in the 2013 ARP. Amortization of the remaining net book value of Plant Mitchell Unit 3 at December 31, 2019, which is expected to be approximately $4 million, and $31 million related to obsolete inventories of certain retired units is expected to be determined by the Georgia PSC in the 2019 base rate case. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plan" for additional information. |
| |
(f) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 3835 years. |
| |
(d)(g) | Comprised of several components including deferred nuclear outages, environmental remediation, building lease, demand-side management tariff under-recovery, and fuel-hedging losses. Deferred nuclear outages are recorded and recovered or amortized over the outage cycles of each nuclear unit, which does not exceed 24 months. The building lease is recorded and recovered or amortized as approved by the Georgia PSC through 2020. The amortization of environmental remediation and demand-side management tariff under-recovery of $54 million at December 31, 2017 is expected to be determined by the Georgia PSC in the 2019 base rate case. Fuel-hedging losses are recovered through the Company's fuel cost recovery mechanism upon final settlement. |
| |
(h) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(e)(i) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. |
| |
(f)(j) | Amortized as approvedComprised of certain customer refunds and fuel-hedging gains. As ordered by the Georgia PSC over periods not exceeding 10 years or through 2024. Amortizationon January 11, 2018, approximately $188 million of obsolete inventoriesthe proceeds pursuant to the Toshiba Guarantee will be determined by the Georgia PSCrefunded to customers in the 2016 base rate case. |
| |
(g) | Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding six years or through 2019. |
| |
(h) | Comprised of several components including deferred nuclear outages, environmental remediation, Medicare subsidy deferred income tax charges, fuel hedging losses, building lease, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding 12 years or through 2022. |
| |
(i) | Comprised primarily of fuel-hedging2018. Fuel-hedging gains which upon final settlement are refunded through the Company's fuel cost recovery mechanism.mechanism upon final settlement. See Note 3 under "Nuclear Construction" for additional information on the customer refunds related to the Toshiba Guarantee. |
| |
(j)(k) | Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.
NOTES (continued)
Georgia Power Company 2017 Annual Report
Revenues
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates.
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee" for additional information.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
Federal ITCs utilized are deferred and, upon utilization, amortized to income as a credit to reduce depreciation over the average life of the related property. The Company had $87 million in federal ITCs at December 31, 2017 that will expire by 2037. State ITCs and other credits are recognized in the period in which the credits are claimed on the state income tax return.generated. The Company had state investment and other tax credit carryforwards totaling $318$495 million at December 31, 2017, which will expire between 20182019 and 20262028 and are expected to be fully utilized by 2022.2026.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction.
The Company's property, plant, and equipment in service consisted of the following at December 31:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Generation | $ | 15,386 |
| | $ | 15,201 |
| $ | 17,038 |
| | $ | 16,668 |
|
Transmission | 5,355 |
| | 5,086 |
| 5,947 |
| | 5,779 |
|
Distribution | 9,151 |
| | 8,913 |
| 9,978 |
| | 9,553 |
|
General | 1,921 |
| | 1,855 |
| 1,870 |
| | 1,813 |
|
Plant acquisition adjustment | 28 |
| | 28 |
| 28 |
| | 28 |
|
Total plant in service | $ | 31,841 |
| | $ | 31,083 |
| $ | 34,861 |
| | $ | 33,841 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.7% in 20152017,2.8% in 2016, and 2.7% in 2014, and 3.0% in 20132015. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from
NOTES (continued)
Georgia Power Company 2017 Annual Report
the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired.
Under the terms of the Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP) and the 2013 ARP, the Company amortized approximately $31 million in 2013 and $14 million in each ofannually from 2014 and 2015through 2016 of its remaining regulatory liability related to other cost of removal obligations.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO)AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-
NOTES (continued)
Georgia Power Company 2015 Annual Report
livedlong-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual and recovery of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, amounts to be recovered are reflected in the balance sheets as a regulatory asset and any accumulated removal costs for thesefuture obligations are reflected in the balance sheets as a regulatory liability.
The ARO liability primarily relates to the Company's ash ponds, landfills, and gypsum cells that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17,in 2015 (CCR Rule). In addition, the Company has retirement obligations related to decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See "Nuclear Decommissioning" herein for additional information on amounts included in rates.
Details of the AROs included in the balance sheets are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Balance at beginning of year | $ | 1,255 |
| | $ | 1,222 |
| $ | 2,532 |
| | $ | 1,916 |
|
Liabilities incurred | 6 |
| | 9 |
| 4 |
| | — |
|
Liabilities settled | (30 | ) | | (12 | ) | (120 | ) | | (123 | ) |
Accretion | 56 |
| | 53 |
| 89 |
| | 77 |
|
Cash flow revisions | 629 |
| | (17 | ) | 133 |
| | 662 |
|
Balance at end of year | $ | 1,916 |
| | $ | 1,255 |
| $ | 2,638 |
| | $ | 2,532 |
|
The increaseIn 2017 and 2016, the increases in cash flow revisions in 2015 isare primarily related to changes to the Company's ash ponds, landfill, and gypsum cell ARO closure dollar and timing estimates associated with the CCR Rule and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. In preparation for the Company's next rate case, and as a part of the Company's three-year ARO update cycle, new closure estimates were developedstrategy for ash ponds, landfills, and gypsum cells nuclear decommissioning, and asbestos AROs. the increases in liabilities settled are primarily related to ash pond closure activity.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 20152017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place or by other methods.closure. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.
The 2014 decrease in cash flow revisions is primarily related to settled AROs for asbestos remediation.cost estimates as necessary.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not
NOTES (continued)
Georgia Power Company 2017 Annual Report
allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of
NOTES (continued)
Georgia Power Company 2015 Annual Report
the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
The Funds participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 20152017 and 20142016, approximately $76 million and $51$56 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $78$77 million and $52$58 million at December 31, 20152017 and 2014,2016, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
At December 31, 2015,2017, investment securities in the Funds totaled $775$929 million, consisting of equity securities of $296$415 million, debt securities of $463$502 million, and $16$12 million of other securities. At December 31, 2014,2016, investment securities in the Funds totaled $789$814 million, consisting of equity securities of $303$326 million, debt securities of $475$477 million, and $11 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the securities lending pool.program.
Sales of the securities held in the Funds resulted in cash proceeds of $568 million, $803 million, and $980 million $669 million,in 2017, 2016, and $705 million in 2015, 2014, and 2013, respectively, all of which were reinvested. For 2017, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $108 million, which included $83 million related to unrealized gains on securities held in the Funds at December 31, 2017. For 2016, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $38 million, which included $14 million related to unrealized losses on securities held in the Funds at December 31, 2016. For 2015, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $3 million, which included $26 million related to unrealized losses on securities held in the Funds at December 31, 2015. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million, which included an immaterial amount related to unrealized gains and losses on securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million, which included $34 million related to unrealized gains on securities held in the Funds at December 31, 20132015. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2015. The site study costs and external trust funds for decommissioning as of December 31, 20152017 based on the Company's ownership interests were as follows:
| | | Plant Hatch | | Plant Vogtle Units 1 and 2 | Plant Hatch | | Plant Vogtle Units 1 and 2 |
Decommissioning periods: | | | | | | |
Beginning year | 2034 |
| | 2047 |
| 2034 |
| | 2047 |
|
Completion year | 2075 |
| | 2079 |
| 2075 |
| | 2079 |
|
| (in millions) | (in millions) |
Site study costs: | | |
Radiated structures | $ | 678 |
| | $ | 568 |
| $ | 678 |
| | $ | 568 |
|
Spent fuel management | 160 |
| | 147 |
| 160 |
| | 147 |
|
Non-radiated structures | 64 |
| | 89 |
| 64 |
| | 89 |
|
Total site study costs | $ | 902 |
| | $ | 804 |
| $ | 902 |
| | $ | 804 |
|
External trust funds | $ | 487 |
| | $ | 288 |
| $ | 583 |
| | $ | 346 |
|
For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs.costs in the Company's 2019 base rate case.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, theThe Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 20152017, 20142016, and 20132015, the average AFUDC rates were 6.5%5.6%, 5.6%6.9%, and 5.3%6.5%, respectively, and AFUDC capitalized was $56$63 million, $62$68 million,, and $4456 million, respectively. AFUDC, net of income taxes, was 3.9%, 4.6%, and 3.3%as a percentage of net income after dividends on preferred and preference stock for 2015was 3.8%, 20144.6%, and 20133.9% for 2017, 2016, and 2015, respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Storm Damage Recovery
The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 20152017 and December 31, 2014,2016, the balance in the regulatory asset related to storm damage was $92$333 million and $98$206 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $62$303 million and $68$176 million included in other regulatory assets, deferred, respectively. The Company expectsannual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this
NOTES (continued)
Georgia Power Company 20152017 Annual Report
the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's earnings. See Note 3 under "Retail Regulatory Matters – Storm Damage Recovery" for additional information.
Environmental Remediation Recovery
The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In December 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP.tariff. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's earnings. As of December 31, 20152017, the balance of the environmental remediation liability was $29$22 million and is included in other current liabilities. As of December 31, 2017, the balance of under recovered environmental remediation costs was $49 million, with approximately $2 million included in other regulatory assets, current and approximately $30$47 million included as other regulatory assets, deferred. As of December 31, 2016, the balance of the environmental remediation liability was $17 million and is included in other current liabilities. As of December 31, 2016, the balance of under recovered environmental remediation costs was $35 million, with approximately $2 million included in other regulatory assets, current and approximately $33 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is chargedrecorded to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statementstatements of cash flows in the same category as the hedged item. See Note 11 for additional information regarding derivatives.
The Company does not offsetoffsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.arrangements. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 20152017.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016.2018. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Georgia PSC and the FERC. For the year ending December 31, 2016,2018, no other postretirement trust contributions are expected to total approximately $14 million.expected.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
| | Assumptions used to determine net periodic costs: | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Pension plans | | | | | | | | | | |
Discount rates – interest costs | 4.18 | % | | 5.02 | % | | 4.27 | % | |
Discount rates – service costs | 4.49 |
| | 5.02 |
| | 4.27 |
| |
Expected long-term return on plan assets | 8.20 |
| | 8.20 |
| | 8.20 |
| |
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
| |
Other postretirement benefit plans | | | | | | |
Discount rate – benefit obligations | | 4.40 | % | | 4.65 | % | | 4.18 | % |
Discount rate – interest costs | 4.03 | % | | 4.85 | % | | 4.04 | % | 3.72 |
| | 3.86 |
| | 4.18 |
|
Discount rate – service costs | 4.39 |
| | 4.85 |
| | 4.04 |
| 4.83 |
| | 5.03 |
| | 4.49 |
|
Expected long-term return on plan assets | 6.48 |
| | 6.75 |
| | 6.74 |
| 7.95 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
| 4.46 |
| | 4.46 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | | |
Discount rate – benefit obligations | | 4.23 | % | | 4.49 | % | | 4.03 | % |
Discount rate – interest costs | | 3.55 |
| | 3.67 |
| | 4.03 |
|
Discount rate – service costs | | 4.63 |
| | 4.88 |
| | 4.39 |
|
Expected long-term return on plan assets | | 6.79 |
| | 6.27 |
| | 6.48 |
|
Annual salary increase | | 4.46 |
| | 4.46 |
| | 3.59 |
|
| | Assumptions used to determine benefit obligations: | 2015 |
| 2014 | 2017 |
| 2016 |
Pension plans |
|
|
|
|
|
|
Discount rate | 4.65 | % |
| 4.18 | % | 3.79 | % |
| 4.40 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.46 |
|
| 4.46 |
|
Other postretirement benefit plans |
|
|
|
|
|
|
Discount rate | 4.49 | % |
| 4.03 | % | 3.68 | % |
| 4.23 | % |
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.46 |
|
| 4.46 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seveneight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $66 million and $17 million, respectively.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 20152017 were as follows:
| | | | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | | 6.50 | % | | 4.50 | % | | 2024 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | | 5.50 |
| | 4.50 |
| | 2024 | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | | 10.00 |
| | 4.50 |
| | 2025 | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 20152017 as follows:
| | | 1 Percent Increase | | 1 Percent Decrease | 1 Percent Increase | | 1 Percent Decrease |
| (in millions) | (in millions) |
Benefit obligation | $ | 58 |
| | $ | (50 | ) | $ | 59 |
| | $ | 50 |
|
Service and interest costs | 2 |
| | (2 | ) | 2 |
| | 2 |
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $3.3$3.8 billion at December 31, 20152017 and $3.5 billion at December 31, 20142016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 3,781 |
| | $ | 3,116 |
| $ | 3,800 |
| | $ | 3,615 |
|
Service cost | 73 |
| | 62 |
| 74 |
| | 70 |
|
Interest cost | 154 |
| | 153 |
| 138 |
| | 136 |
|
Benefits paid | (188 | ) | | (149 | ) | (187 | ) | | (164 | ) |
Actuarial loss (gain) | (205 | ) | | 599 |
| |
Actuarial (gain) loss | | 363 |
| | 143 |
|
Balance at end of year | 3,615 |
| | 3,781 |
| 4,188 |
| | 3,800 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 3,383 |
| | 3,085 |
| 3,621 |
| | 3,196 |
|
Actual return (loss) on plan assets | (13 | ) | | 285 |
| 610 |
| | 288 |
|
Employer contributions | 14 |
| | 162 |
| 14 |
| | 301 |
|
Benefits paid | (188 | ) | | (149 | ) | (187 | ) | | (164 | ) |
Fair value of plan assets at end of year | 3,196 |
| | 3,383 |
| 4,058 |
| | 3,621 |
|
Accrued liability | $ | (419 | ) | | $ | (398 | ) | $ | (130 | ) | | $ | (179 | ) |
At December 31, 20152017, the projected benefit obligations for the qualified and non-qualified pension plans were $3.5$4.0 billion and $151$153 million, respectively. All pension plan assets are related to the qualified pension plan.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Amounts recognized in the balance sheets at December 31, 20152017 and 20142016 related to the Company's pension plans consist of the following:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Prepaid pension costs | | $ | 23 |
| | $ | — |
|
Other regulatory assets, deferred | $ | 1,076 |
| | $ | 1,102 |
| 1,105 |
| | 1,129 |
|
Current liabilities, other | (13 | ) | | (12 | ) | |
Other current liabilities | | (15 | ) | | (14 | ) |
Employee benefit obligations | (406 | ) | | (386 | ) | (138 | ) | | (165 | ) |
Presented below are the amounts included in regulatory assets at December 31, 20152017 and 20142016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2016.2018.
| | | 2015 | | 2014 | | Estimated Amortization in 2016 | 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) | (in millions) |
Prior service cost | $ | 8 |
| | $ | 17 |
| | $ | 5 |
| $ | 14 |
| | $ | 17 |
| | $ | 2 |
|
Net (gain) loss | 1,068 |
| | 1,085 |
| | 55 |
| 1,091 |
| | 1,112 |
| | 69 |
|
Regulatory assets | $ | 1,076 |
| | $ | 1,102 |
| | | $ | 1,105 |
| | $ | 1,129 |
| | |
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 20152017 and 20142016 are presented in the following table:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Regulatory assets: | | | | | | |
Beginning balance | $ | 1,102 |
| | $ | 610 |
| $ | 1,129 |
| | $ | 1,076 |
|
Net (gain) loss | 59 |
| | 543 |
| 36 |
| | 99 |
|
Change in prior service costs | | — |
| | 14 |
|
Reclassification adjustments: | | | | | | |
Amortization of prior service costs | (9 | ) | | (10 | ) | (3 | ) | | (5 | ) |
Amortization of net gain (loss) | (76 | ) | | (41 | ) | (57 | ) | | (55 | ) |
Total reclassification adjustments | (85 | ) | | (51 | ) | (60 | ) | | (60 | ) |
Total change | (26 | ) | | 492 |
| (24 | ) | | 53 |
|
Ending balance | $ | 1,076 |
| | $ | 1,102 |
| $ | 1,105 |
| | $ | 1,129 |
|
Components of net periodic pension cost were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Service cost | $ | 73 |
| | $ | 62 |
| | $ | 69 |
| $ | 74 |
| | $ | 70 |
| | $ | 73 |
|
Interest cost | 154 |
| | 153 |
| | 138 |
| 138 |
| | 136 |
| | 154 |
|
Expected return on plan assets | (251 | ) | | (228 | ) | | (212 | ) | (283 | ) | | (258 | ) | | (251 | ) |
Recognized net loss | 76 |
| | 41 |
| | 74 |
| |
Recognized net (gain) loss | | 57 |
| | 55 |
| | 76 |
|
Net amortization | 9 |
| | 10 |
| | 10 |
| 3 |
| | 5 |
| | 9 |
|
Net periodic pension cost | $ | 61 |
| | $ | 38 |
| | $ | 79 |
| $ | (11 | ) | | $ | 8 |
| | $ | 61 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the
NOTES (continued)
Georgia Power Company 2017 Annual Report
market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 20152017, estimated benefit payments were as follows:
| | | Benefit Payments | Benefit Payments |
| (in millions) | (in millions) |
2016 | $ | 168 |
| |
2017 | 176 |
| |
2018 | 183 |
| $ | 196 |
|
2019 | 189 |
| 201 |
|
2020 | 197 |
| 207 |
|
2021 to 2025 | 1,085 |
| |
2021 | | 210 |
|
2022 | | 216 |
|
2023 to 2027 | | 1,156 |
|
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 864 |
| | $ | 723 |
| $ | 847 |
| | $ | 854 |
|
Service cost | 7 |
| | 6 |
| 7 |
| | 6 |
|
Interest cost | 34 |
| | 34 |
| 29 |
| | 30 |
|
Benefits paid | (45 | ) | | (44 | ) | (51 | ) | | (45 | ) |
Actuarial loss (gain) | (22 | ) | | 142 |
| |
Plan amendment | 12 |
| | — |
| |
Actuarial (gain) loss | | 28 |
| | (1 | ) |
Retiree drug subsidy | 4 |
| | 3 |
| 3 |
| | 3 |
|
Balance at end of year | 854 |
| | 864 |
| 863 |
| | 847 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 395 |
| | 407 |
| 354 |
| | 358 |
|
Actual return (loss) on plan assets | (6 | ) | | 21 |
| 54 |
| | 21 |
|
Employer contributions | 10 |
| | 8 |
| 26 |
| | 17 |
|
Benefits paid | (41 | ) | | (41 | ) | (48 | ) | | (42 | ) |
Fair value of plan assets at end of year | 358 |
| | 395 |
| 386 |
| | 354 |
|
Accrued liability | $ | (496 | ) | | $ | (469 | ) | $ | (477 | ) | | $ | (493 | ) |
Amounts recognized in the balance sheets at December 31, 20152017 and 20142016 related to the Company's other postretirement benefit plans consist of the following:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Other regulatory assets, deferred | $ | 223 |
| | $ | 213 |
| $ | 202 |
| | $ | 213 |
|
Employee benefit obligations | (496 | ) | | (469 | ) | (477 | ) | | (493 | ) |
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Presented below are the amounts included in regulatory assets at December 31, 20152017 and 20142016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2016.2018.
| | | 2015 | | 2014 | | Estimated Amortization in 2016 | 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) | (in millions) |
Prior service cost | $ | 8 |
| | $ | (5 | ) | | $ | 1 |
| $ | 5 |
| | $ | 6 |
| | $ | 1 |
|
Net (gain) loss | 215 |
| | 218 |
| | 9 |
| 197 |
| | 207 |
| | 9 |
|
Regulatory assets | $ | 223 |
| | $ | 213 |
| | | $ | 202 |
| | $ | 213 |
| | |
The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 20152017 and 20142016 are presented in the following table:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Regulatory assets: | | | | | | |
Beginning balance | $ | 213 |
| | $ | 69 |
| $ | 213 |
| | $ | 223 |
|
Net (gain) loss | 9 |
| | 146 |
| (2 | ) | | — |
|
Change in prior service costs | 12 |
| | — |
| |
Reclassification adjustments: | | | | | | |
Amortization of prior service costs | | (1 | ) | | (1 | ) |
Amortization of net gain (loss) | (11 | ) | | (2 | ) | (8 | ) | | (9 | ) |
Total reclassification adjustments | | (9 | ) | | (10 | ) |
Total change | 10 |
| | 144 |
| (11 | ) | | (10 | ) |
Ending balance | $ | 223 |
| | $ | 213 |
| $ | 202 |
| | $ | 213 |
|
Components of the other postretirement benefit plans' net periodic cost were as follows:
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Service cost | $ | 7 |
| | $ | 6 |
| | $ | 7 |
| $ | 7 |
| | $ | 6 |
| | $ | 7 |
|
Interest cost | 34 |
| | 34 |
| | 31 |
| 29 |
| | 30 |
| | 34 |
|
Expected return on plan assets | (24 | ) | | (25 | ) | | (24 | ) | (25 | ) | | (22 | ) | | (24 | ) |
Net amortization | 11 |
| | 2 |
| | 12 |
| 9 |
| | 10 |
| | 11 |
|
Net periodic postretirement benefit cost | $ | 28 |
| | $ | 17 |
| | $ | 26 |
| $ | 20 |
| | $ | 24 |
| | $ | 28 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
| | | Benefit Payments | | Subsidy Receipts | | Total | Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) | (in millions) |
2016 | $ | 53 |
| | $ | (4 | ) | | $ | 49 |
| |
2017 | 55 |
| | (4 | ) | | 51 |
| |
2018 | 58 |
| | (5 | ) | | 53 |
| $ | 55 |
| | $ | (3 | ) | | $ | 52 |
|
2019 | 59 |
| | (5 | ) | | 54 |
| 55 |
| | (3 | ) | | 52 |
|
2020 | 60 |
| | (5 | ) | | 55 |
| 56 |
| | (3 | ) | | 53 |
|
2021 to 2025 | 305 |
| | (28 | ) | | 277 |
| |
2021 | | 57 |
| | (4 | ) | | 53 |
|
2022 | | 58 |
| | (4 | ) | | 54 |
|
2023 to 2027 | | 288 |
| | (21 | ) | | 267 |
|
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 20152017 and 20142016, along with the targeted mix of assets for each plan, is presented below:
| | | Target | | 2015 | | 2014 | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | | | | | |
Domestic equity | 26 | % | | 30 | % | | 30 | % | 26 | % | | 31 | % | | 29 | % |
International equity | 25 |
| | 23 |
| | 23 |
| 25 |
| | 25 |
| | 22 |
|
Fixed income | 23 |
| | 23 |
| | 27 |
| 23 |
| | 24 |
| | 29 |
|
Special situations | 3 |
| | 2 |
| | 1 |
| 3 |
| | 1 |
| | 2 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
| 14 |
| | 13 |
| | 13 |
|
Private equity | 9 |
| | 6 |
| | 5 |
| 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | | | | | | |
Domestic equity | 40 | % | | 34 | % | | 38 | % | 36 | % | | 38 | % | | 35 | % |
International equity | 21 |
| | 27 |
| | 26 |
| 24 |
| | 24 |
| | 24 |
|
Domestic fixed income | 23 |
| | 25 |
| | 24 |
| 33 |
| | 31 |
| | 35 |
|
Global fixed income | 9 |
| | 8 |
| | 7 |
| |
Special situations | 1 |
| | — |
| | — |
| 1 |
| | 1 |
| | 1 |
|
Real estate investments | 4 |
| | 4 |
| | 4 |
| 4 |
| | 4 |
| | 4 |
|
Private equity | 2 |
| | 2 |
| | 1 |
| 2 |
| | 2 |
| | 1 |
|
Total | 100 | % | | 100 | % | | 100 | % | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
NOTES (continued)
Georgia Power Company 2017 Annual Report
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 20152017 and 20142016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.
Real estate investments, private equity, and private equity.special situations investments. Investments in real estate, private equity, and real estatespecial situations are generally classified as Level 3Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniquesTechniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally useanalysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments.appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets.assets less liabilities.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
The fair values of pension plan assets as of December 31, 20152017 and 20142016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | �� | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Domestic equity* | $ | 565 |
| | $ | 236 |
| | $ | — |
| | $ | — |
| | $ | 801 |
| |
International equity* | 412 |
| | 343 |
| | — |
| | — |
| | 755 |
| |
Domestic equity(*) | | $ | 819 |
| | $ | 394 |
| | $ | — |
| | $ | — |
| | $ | 1,213 |
|
International equity(*) | | 529 |
| | 477 |
| | — |
| | — |
| | 1,006 |
|
Fixed income: | | | | | | | | | | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 157 |
| | — |
| | — |
| | 157 |
| — |
| | 286 |
| | — |
| | — |
| | 286 |
|
Mortgage- and asset-backed securities | — |
| | 69 |
| | — |
| | — |
| | 69 |
| — |
| | 3 |
| | — |
| | — |
| | 3 |
|
Corporate bonds | — |
| | 394 |
| | — |
| | — |
| | 394 |
| — |
| | 409 |
| | — |
| | — |
| | 409 |
|
Pooled funds | — |
| | 173 |
| | — |
| | — |
| | 173 |
| — |
| | 221 |
| | — |
| | — |
| | 221 |
|
Cash equivalents and other | — |
| | 50 |
| | — |
| | — |
| | 50 |
| 74 |
| | 4 |
| | — |
| | — |
| | 78 |
|
Real estate investments | 103 |
| | — |
| | — |
| | 421 |
| | 524 |
| 160 |
| | — |
| | — |
| | 404 |
| | 564 |
|
Special situations | | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
Private equity | — |
| | — |
| | — |
| | 220 |
| | 220 |
| — |
| | — |
| | — |
| | 228 |
| | 228 |
|
Total | $ | 1,080 |
| | $ | 1,422 |
| | $ | — |
| | $ | 641 |
| | $ | 3,143 |
| $ | 1,582 |
| | $ | 1,794 |
| | $ | — |
| | $ | 693 |
| | $ | 4,069 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Georgia Power Company 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 595 |
| | $ | 246 |
| | $ | — |
| | $ | — |
| | $ | 841 |
|
International equity* | 373 |
| | 344 |
| | — |
| | — |
| | 717 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 244 |
| | — |
| | — |
| | 244 |
|
Mortgage- and asset-backed securities | — |
| | 66 |
| | — |
| | — |
| | 66 |
|
Corporate bonds | — |
| | 398 |
| | — |
| | — |
| | 398 |
|
Pooled funds | — |
| | 179 |
| | — |
| | — |
| | 179 |
|
Cash equivalents and other | 1 |
| | 230 |
| | — |
| | — |
| | 231 |
|
Real estate investments | 102 |
| | — |
| | — |
| | 391 |
| | 493 |
|
Private equity | — |
| | — |
| | — |
| | 199 |
| | 199 |
|
Total | $ | 1,071 |
| | $ | 1,707 |
| | $ | — |
| | $ | 590 |
| | $ | 3,368 |
|
Liabilities: | | | | | | | | | |
Derivatives | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1 | ) |
Total | $ | 1,070 |
| | $ | 1,707 |
| | $ | — |
| | $ | 590 |
| | $ | 3,367 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 686 |
| | $ | 317 |
| | $ | — |
| | $ | — |
| | $ | 1,003 |
|
International equity(*) | 420 |
| | 380 |
| | — |
| | — |
| | 800 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 201 |
| | — |
| | — |
| | 201 |
|
Mortgage- and asset-backed securities | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
Corporate bonds | — |
| | 338 |
| | — |
| | — |
| | 338 |
|
Pooled funds | — |
| | 179 |
| | — |
| | — |
| | 179 |
|
Cash equivalents and other | 340 |
| | 1 |
| | — |
| | — |
| | 341 |
|
Real estate investments | 106 |
| | — |
| | — |
| | 394 |
| | 500 |
|
Special situations | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
Private equity | — |
| | — |
| | — |
| | 188 |
| | 188 |
|
Total | $ | 1,552 |
| | $ | 1,420 |
| | $ | — |
| | $ | 643 |
| | $ | 3,615 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Georgia Power Company 2015 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 20152017 and 20142016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Domestic equity* | $ | 30 |
| | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 66 |
| |
International equity* | 12 |
| | 41 |
| | — |
| | — |
| | 53 |
| |
Domestic equity(*) | | $ | 53 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 64 |
|
International equity(*) | | 14 |
| | 46 |
| | — |
| | — |
| | 60 |
|
Fixed income: | | | | | | | | | | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 5 |
| | — |
| | — |
| | 5 |
| — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Mortgage- and asset-backed securities | — |
| | 2 |
| | — |
| | — |
| | 2 |
| |
Corporate bonds | — |
| | 12 |
| | — |
| | — |
| | 12 |
| — |
| | 11 |
| | — |
| | — |
| | 11 |
|
Pooled funds | — |
| | 30 |
| | — |
| | — |
| | 30 |
| — |
| | 41 |
| | — |
| | — |
| | 41 |
|
Cash equivalents and other | 10 |
| | 6 |
| | — |
| | — |
| | 16 |
| 4 |
| | — |
| | — |
| | — |
| | 4 |
|
Trust-owned life insurance | — |
| | 158 |
| | — |
| | — |
| | 158 |
| — |
| | 173 |
| | — |
| | — |
| | 173 |
|
Real estate investments | 3 |
| | — |
| | — |
| | 12 |
| | 15 |
| 6 |
| | — |
| | — |
| | 11 |
| | 17 |
|
Special situations | | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 7 |
| | 7 |
| — |
| | — |
| | — |
| | 6 |
| | 6 |
|
Total | $ | 55 |
| | $ | 290 |
| | $ | — |
| | $ | 19 |
| | $ | 364 |
| $ | 77 |
| | $ | 288 |
| | $ | — |
| | $ | 19 |
| | $ | 384 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Georgia Power Company 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 53 |
| | $ | 40 |
| | $ | — |
| | $ | — |
| | $ | 93 |
|
International equity* | 11 |
| | 45 |
| | — |
| | — |
| | 56 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
Mortgage- and asset-backed securities | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Corporate bonds | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
Pooled funds | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Cash equivalents and other | 8 |
| | 11 |
| | — |
| | — |
| | 19 |
|
Trust-owned life insurance | — |
| | 162 |
| | — |
| | — |
| | 162 |
|
Real estate investments | 3 |
| | — |
| | — |
| | 12 |
| | 15 |
|
Private equity | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
Total | $ | 75 |
| | $ | 308 |
| | $ | — |
| | $ | 18 |
| | $ | 401 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 45 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | 54 |
|
International equity(*) | 11 |
| | 37 |
| | — |
| | — |
| | 48 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Corporate bonds | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
Pooled funds | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
Cash equivalents and other | 15 |
| | — |
| | — |
| | — |
| | 15 |
|
Trust-owned life insurance | — |
| | 162 |
| | — |
| | — |
| | 162 |
|
Real estate investments | 3 |
| | — |
| | — |
| | 11 |
| | 14 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 5 |
| | 5 |
|
Total | $ | 74 |
| | $ | 260 |
| | $ | — |
| | $ | 18 |
| | $ | 352 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up tomatches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2015, 2014,2017, 2016, and 20132015 were $26 million, $25$27 million, and $2426 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
In 2011, plaintiffs filed a putative class action against the Company in the Superior Court of Fulton County, Georgia alleging that the Company's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. The Company filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is expected in late 2018. The Company believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.
The Company is also subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
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Environmental Matters
Environmental Remediation
The Company must comply with environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. See Note 1 under "Environmental Remediation Recovery" for additional information.
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December 31, 2017 and 2016 was $22 million and $17 million, respectively. The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, the Company entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between the Company and that PRP) for paying and performing certain investigation, assessment remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of othersuch sites are anticipated.is expected.
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with the Company that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Hatch and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract.
In December 2014, the Court of Federal Claims entered a judgment in favor of the Company in its spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. On March 19,In 2015, the Company recovered approximately $18 million, based on its ownership interests. In March 2015, the Companyinterests, which was credited the award to accounts where the original costs were charged, and reducedused to reduce rate base, fuel, and cost of service for the benefit of customers.
In March 2014, the Company filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On October 10, 2017, the Company filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 20152017 for any potential recoveries from the additionalpending lawsuits. The final outcome of these matters cannot be determined at this time; however,time. However, the Company expects to credit any recovery back for the benefit of customers in accordance with direction from the Georgia PSC and, therefore, no material impact on the Company's net income is expected.
On-site dry spent fuel storage facilities are operational at Plant Vogtle Units 1 and 2 and Plant Hatch. Facilities can be expanded to accommodate spent fuel through the expected life of each plant.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Rate PlansFERC in 2015.
In 2013,December 2016, the Georgia PSC votedtraditional electric operating companies (including the Company) and Southern Power filed an amendment to approvetheir market-based rate tariff that proposed certain changes to the 2013 ARP. The 2013 ARP reflectsenergy auction, as well as several non-tariff changes. On February 2, 2017, the settlement agreement among the Company, the Georgia PSC's Public Interest Advocacy Staff, and 11FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the 13 intervenors.energy auction, finding that all of these changes would provide adequate alternative mitigation for
In January 2014, in accordance with the 2013 ARP, the Company increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) ECCR tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by
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approximately $1 million;the traditional electric operating companies' (including the Company's) and (4) Municipal Franchise Fee (MFF) tariffSouthern Power's potential to exert market power in certain areas served by approximately $4 million, forthe traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a total increase in base revenues of approximately $110 million.separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 19, 2015,2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
Rate Plans
Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in April 2016, the 2013 ARP will continue in effect until December 31, 2019, and the Company will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, the Company and Atlanta Gas Light Company each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each will be shared on a 60/40 basis with their respective customers; thereafter, all merger savings will be retained by customers.
In accordance with the 2013 ARP, the Georgia PSC approved an increase to tariffs effective January 1, 2015 as follows: (1) traditional base tariff rates by approximately $107 million; (2) ECCR tariff by approximately $23 million; (3) DSM tariffs by approximately $3 million; and (4) MFF tariff by approximately $3 million, for a total increase in base revenues of approximately $136 million.
On December 16, 2015, in accordance with the 2013 ARP, the Georgia PSC approved an increaseincreases to tariffs effective January 1, 2016 as follows: (1) traditional base tariff rates by approximately $49 million; (2) ECCR tariff by approximately $75 million; (3) DSMDemand-Side Management tariffs by approximately $3 million; and (4) MFFMunicipal Franchise Fee tariff by approximately $13 million, for a total increase in base revenues of approximately $140 million. There were no changes to these tariffs in 2017.
Under the 2013 ARP, the Company's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2014,2015, the Company's retail ROE was within the allowed retail ROE range. In 2016, the Company's retail ROE exceeded 12.00%, and the Company will refund to retail customers approximately $11$44 million in 2016,2018, as approved by the Georgia PSC on February 18, 2016.January 16, 2018. In 2015,2017, the Company's retail ROE was within the allowed retail ROE range.range, subject to review and approval by the Georgia PSC.
TheOn January 19, 2018, the Georgia PSC issued an order on the Tax Reform Legislation, which was amended on February 16, 2018 (Tax Order). In accordance with the Tax Order, the Company is required to file a general base rate casesubmit its analysis of the Tax Reform Legislation and related recommendations to address the related impacts on the Company's cost of service and annual revenue requirements by July 1, 2016, in response to which the Georgia PSC wouldMarch 6, 2018. The ultimate outcome of this matter cannot be expected to determine whether the 2013 ARP should be continued, modified, or discontinued.determined at this time.
Integrated Resource Plan
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired and operations were discontinued at Plant Mitchell Unit 3 (155 MWs) by April 15, 2015, and Plant Kraft Units 1 through 4 (316 MWs) were retired on October 13, 2015. The switch to natural gas as the primary fuel was completed at Plant Yates Units 6 and 7 by June 2015 and at Plant Gaston Units 1 through 4 by December 2015.
In the 2013 ARP,July 2016, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years ending December 2022 and the amortization of the remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024.
On January 29, 2016, the Company filed itsCompany's triennial IRPIntegrated Resource Plan (2016 IRP). The filing included a request to decertify including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 (17 MWs) upon approval, as well as the decertification of the Intercession City unit (143 MWs total capacity). In August 2016, IRP. The 2016 IRP also reflects thatthe Plant Mitchell and Plant Kraft units were retired and the Company exercised its contractual option to sellsold its 33% ownership interest in the Intercession City unit (143 MWs total capacity) to Duke Energy Florida, Inc. See Note 4 for additional information.LLC.
InAdditionally, the Georgia PSC approved the Company's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved the Company requested reclassification of the remaining net book value of Plant Mitchell Unit 3 as of its retirement date, to a regulatory asset to be amortized over a period equal to the unit's remaining useful life. The Company also requested that the Georgia PSC approve the deferral of the costand costs associated with materials and supplies remaining at the unit retirement datesdate to a regulatory asset, to be amortized over a period deemed appropriate byasset. Recovery of the Georgia PSC.
The decertification and retirement of these units are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's ordersunit's net book value will continue through December 31, 2019, as provided in the 2016 IRP2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and next general base rate case.
Additionally,costs associated with materials and supplies remaining at the 2016 IRP included a Renewable Energy Development Initiative requesting to procure up to 525 MWs of renewable resources utilizing market-based prices established through a competitive bidding process to expand the Company’s existing renewable initiatives, including the Advanced Solar Initiative.
A decision from the Georgia PSC on the 2016 IRP is expected in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reductionunit retirement date was deferred for consideration in the Company's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, the Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. The2019 base rate case.
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Georgia Power Company 20152017 Annual Report
The Georgia PSC also approved the Renewable Energy Development Initiative (REDI) to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by the Company was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.
In 2017, the Company filed for and received certification for 510 MWs of REDI utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2019. The Company also filed for and received approval to develop several solar generation projects to fulfill the approved self-build capacity.
In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. On March 7, 2017, the Georgia PSC approved the Company's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costcosts. The timing of recovery includesfor costs associated with a natural gas hedging program, as approvedincurred of approximately $50 million is expected to be determined by the Georgia PSC in 2015, allowing it to use an array of derivative instruments within a 48-month time horizon effective January 1, 2016. See Note 11 under "Energy-Related Derivatives" for additional information. On December 15,future rate case.
Fuel Cost Recovery
The Company has established fuel cost recovery rates approved by the Georgia PSC. In 2015, the Georgia PSC approved the Company's request to lower annual billings by approximately $350 million effective January 1, 2016. In May 2016, the Georgia PSC approved the Company's request to further lower annual billings under an interim fuel rider by approximately $313 million effective June 1, 2016, which expired on December 31, 2017. The Georgia PSC will review the Company's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case unless the Company deems it necessary to file a fuel case at an earlier time. The Company continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under recovered fuel balance exceeds $200 million.
The Company's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 48-month time horizon.
The Company's under recovered fuel balance totaled $165 million at December 31, 2017 and is included in current assets. At December 31, 2016, the Company's over recovered fuel balance totaled approximately $116$84 million at December 31, 2015 and is included in current liabilities and other deferred liabilities. At December 31, 2014, the Company's underover recovered fuel balance totaled approximately $199 million and was included in current assets and other deferred charges and assets.clause revenues, current.
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow.
Storm Damage Recovery
The Company is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. Hurricanes Irma and Matthew caused significant damage to the Company's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to these hurricanes deferred in the regulatory asset for storm damage totaled approximately $260 million. At December 31, 2017, the total balance in the regulatory asset related to storm damage was $333 million. The rate of storm damage cost recovery is expected to be adjusted as part of the Company's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on the Company's financial statements. See Note 1 under "Storm Damage Recovery" for additional information regarding the Company's storm damage reserve.
Nuclear Construction
Project Status
In 2008,2009, the Company, acting for itselfGeorgia PSC certified construction of Plant Vogtle Units 3 and as agent for Oglethorpe Power Corporation (OPC),4. In 2012, the Municipal Electric AuthorityNRC issued the related combined construction and operating licenses, which allowed full construction of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (Westinghouse and Stone & Webster, Inc., collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities atto begin. Until March 2017, construction on Plant Vogtle (VogtleUnits 3 and 4 Agreement).continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired on July 27, 2017 when the Vogtle Services Agreement became effective. In August 2017, following completion of comprehensive cost to complete and cancellation cost assessments, the Company filed its seventeenth
NOTES (continued)
Georgia Power Company 2017 Annual Report
VCM report with the Georgia PSC, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor. On December 21, 2017, the Georgia PSC approved the Company's recommendation to continue construction.
The Company expects Plant Vogtle Units 3 and 4 to be placed in service by November 2021 and November 2022, respectively. The Company's revised capital cost forecast for its 45.7% proportionate share of Plant Vogtle Units 3 and 4 is $8.8 billion ($7.3 billion after reflecting the impact of payments received under the Guarantee Settlement Agreement and the Customer Refunds, each as defined herein). The Company's CWIP balance for Plant Vogtle Units 3 and 4 was $3.3 billion at December 31, 2017, which is net of the Guarantee Settlement Agreement payments less the Customer Refunds. The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy
In 2008, the Company, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. TheUnder the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In the first quarter 2016, Westinghouse delivered to the Vogtle Owners a total of $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. The Company, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of December 31, 2017.
On June 9, 2017, the Company and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, also providesToshiba acknowledged the amount of its obligation was $3.68 billion (Guarantee Obligations), of which the Company's proportionate share was approximately $1.7 billion. The Guarantee Settlement Agreement provided for liquidated damages upona schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Company, the other Vogtle Owners, certain affiliates of the Municipal Electric Authority of Georgia (MEAG Power), and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (Guarantee Settlement Agreement Amendment). The Guarantee Settlement Agreement Amendment provided that Toshiba's remaining payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Guarantee Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Company, the other Vogtle Owners, and certain affiliates of MEAG Power against Westinghouse, and the Company and the other Vogtle Owners surrendered the Westinghouse Letters of Credit.
Additionally, on June 9, 2017, the Company, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement, which was amended and restated on July 20, 2017. On July 20, 2017, the bankruptcy court approved the EPC Contractor's failuremotion seeking authorization to fulfill(i) enter into the scheduleVogtle Services Agreement, (ii) assume and performance guarantees, subjectassign to a cap. In addition,the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Vogtle Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, provides for limited cost sharingbecame effective upon approval by the DOE on July 27, 2017. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable toupon 30 days' written notice.
Effective October 23, 2017, the Company, (basedacting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). Facility design and engineering remains the responsibility of the EPC Contractor under the Vogtle Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on the Company's ownership interest) of approximately $114 million.Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (and not(not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the ContractorBechtel under the Vogtle 3 and 4Bechtel Agreement. The Company's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from CB&I (Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and CB&I's The Shaw Group Inc., respectively. Subject to the consent of the DOE, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. will be terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, on January 13, 2016, as a result of recent credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $900 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
The Vogtle Owners may terminate
NOTES (continued)
Georgia Power Company 2017 Annual Report
the Vogtle 3 and 4Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination costs. The Contractortermination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Vogtle 3 and 4Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspension or delayssuspensions of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between the Company and the DOE, the Company is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In 2009,On November 2, 2017, the NRC issuedVogtle Owners entered into an Early Site Permit and Limited Work Authorization which allowed limited workamendment to begin ontheir joint ownership agreements for Plant Vogtle Units 3 and 4. The NRC certified4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Westinghouse Design Control Document, as amended (DCD), forVogtle Joint Ownership Agreements, the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receiptholders of at least 90% of the COLs allowed fullownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction to begin. There have been technical and procedural challengesif certain adverse events occur, including (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or the Company determines that any of the Company's costs relating to the construction and licensing of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the federalprimary construction contractor and state level, and additional challenges may arise(ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against the Company or Southern Nuclear for any action or inaction in connection with their performance as construction proceeds.agent for the Vogtle Owners is limited to removal of the Company and/or Southern Nuclear as agent, except in cases of willful misconduct.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4.4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects
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Georgia Power Company 2015 Annual Report
certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by includingup to the related CWIP accounts in rate base duringcertified capital cost of $4.418 billion. As of December 31, 2017, the construction period. The Georgia PSC approved an initial NCCR tariffCompany had recovered approximately $1.6 billion of approximately $223 million effectivefinancing costs. On January 1, 2011, as well as increases30, 2018, the Company filed to decrease the NCCR tariff ofby approximately $35 million, $50 million, $60effective April 1, 2018, pending Georgia PSC approval. The decrease reflects the payments received under the Guarantee Settlement Agreement, refunds to customers ordered by the Georgia PSC aggregating approximately $188 million $27 million,(Customer Refunds), and $19 million effective January 1, 2012, 2013, 2014, 2015,the estimated effects of Tax Reform Legislation. The Customer Refunds were recognized as a regulatory liability as of December 31, 2017 and 2016, respectively.will be paid in three installments of $25 to each retail customer no later than the third quarter 2018.
The Company is required to file semi-annual Vogtle Construction Monitoring (VCM)VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by the Company increase by 5% above the certified cost or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, the Company requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation (2013 Stipulation) between the Company and the staff of the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company.
On April 15, 2015,December 20, 2016, the Georgia PSC issuedvoted to approve a procedural ordersettlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the twelfthfifteenth VCM report. On December 21, 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by the Company in the seventeenth VCM report which included a requested amendment (Requested Amendment)and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to the Plant Vogtle Units 3 and 4 certificate4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to reflect the Contractor'sContractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.680 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) the Company would have the burden to show that any capital costs above $5.680 billion were prudent, and (c) a revised capital cost forecast for completionof $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) is found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 (second quarter of 2019should be completed, with Southern Nuclear serving as project manager and second quarter of 2020, respectively)Bechtel as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs,primary contractor; (v) approved and other operational readiness costs to includedeemed reasonable the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost ofCompany's revised schedule placing Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will be included in rate base, provided the Company shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service in November 2021 and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.November 2022, respectively;
In 2012, the Vogtle Owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. In June 2015, the Contractor updated its estimated damages to an aggregate (based on the Company's ownership interest) of approximately $714 million (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation).
On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, the Company, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will now commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4, rather than the original guaranteed substantial completion dates under the Vogtle 3 and 4 Agreement; and (v) provide that the Company, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $120 million has been paid previously under the dispute resolution procedures of the Vogtle 3 and 4 Agreement. Further, subsequent to December 31, 2015, the Company paid approximately $121 million under the terms of the Contractor Settlement Agreement. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security,for which costs were reflected in the Company's previously
NOTES (continued)
Georgia Power Company 20152017 Annual Report
disclosed in-service(vi) confirmed that the revised cost estimate. Further, as partforecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than the Company's average cost of long-term debt); (viii) reduced the settlementROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to the Company's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in connectionthe Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than the Company's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $20 million in 2016 and $25 million in 2017 and are estimated to have negative earnings impacts of approximately $120 million in 2018 and an aggregate of $585 million from 2019 to 2022. In its January 11, 2018 order, the Georgia PSC stated if other certain conditions and assumptions upon which the Company's seventeenth VCM report are based do not materialize, both the Company and the Georgia PSC reserve the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Acquisition: (i) WestinghouseFulton County Superior Court. The Company believes the appeal has engaged Fluor Enterprises, Inc.,no merit; however, an adverse outcome in this appeal could have a subsidiarymaterial impact on the Company's results of Fluor Corporation, as a new construction subcontractor;operations, financial condition, and (ii) the Vogtle Owners, CB&I, and liquidity.
The Shaw Group Inc. have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the constructionIRS allocated PTCs to each of Plant Vogtle Units 3 and 4, that occurred on orwhich originally required the applicable unit to be placed in service before 2021. Under the dateBipartisan Budget Act of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.
On January 21, 2016, the Company submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. On February 2, 2016, the Georgia PSC ordered the Company to file supplemental information by April 5, 2016 in support of the Contractor Settlement Agreement and the Company's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. Following the Company's filing under the order, the Staff will conduct a review of all costs incurred related to2018, Plant Vogtle Units 3 and 4 continue to qualify for PTCs. The nominal value of the schedule for completionCompany's portion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the StaffPTCs is authorized to engage in related settlement discussions with the Company and any intervenors.approximately $500 million per unit.
TheIn its January 11, 2018 order, provides that the Staff is required to report to the Georgia PSC by October 5, 2016 with respectalso approved $542 million of capital costs incurred during the seventeenth VCM reporting period (January 1, 2017 to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing the Company to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
June 30, 2017). The Georgia PSC has approved thirteenseventeen VCM reports covering the periods through June 30, 2015,2017, including total construction capital costs incurred which through that date totaled $3.1of $4.4 billion. On February 26, 2016, theThe Company filedexpects to file its fourteentheighteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. The Company ison February 28, 2018 requesting approval of $160approximately $450 million of construction capital costs (before payments received under the Guarantee Settlement Agreement and the Customer Refunds) incurred during that period. The Company anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion.July 1, 2017 through December 31, 2017. The Company's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.6$4.8 billion as of December 31, 2015.2017, or $3.3 billion net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The ultimate outcome of these matters cannot be determined at this time.
Cost and Schedule
The Company's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 with in service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Project capital cost forecast | $ | 7.3 |
|
Net investment as of December 31, 2017 | (3.4 | ) |
Remaining estimate to complete | $ | 3.9 |
|
Note: Excludes financing costs capitalized through AFUDC and is net of payments received under the Guarantee Settlement Agreement and the Customer Refunds.
The Company estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $1.6 billion had been incurred through December 31, 2017.
As construction continues, challenges with management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly, and installation of plant systems, structures, and components (some of which are based on new technology and have not yet operated in the global nuclear industry at this scale), or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance
NOTES (continued)
Georgia Power Company 2017 Annual Report
processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issuesmatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
Future claims by the Contractor or the Company (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.costs.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of December 31, 2017, the Company had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among the Company, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. SEGCO uses natural gas as the primary fuel source for 1,000 MWs of its generating capacity. The capacity of these units is sold equally to the Company and Alabama Power under a power contract. The Company and Alabama Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and aan ROE. The Company's share of purchased power totaled $78 million in 20152017, $8457 million in 20142016, and $9178 million in 20132015 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method. See Note 7 under "Guarantees" for additional information.
NOTES (continued)
Georgia Power Company 2015 Annual Report
The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC,Oglethorpe Power Corporation (OPC), MEAG Power, the City of Dalton, Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners, doing business as Dalton Utilities, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC, whowhich is the operator of the plant. TheIn August 2016, the Company and Duke Energy Florida, Inc. jointly own asold its 33% ownership interest in the Intercession City combustion turbine unit (Intercession City) operated by Duke Energy Florida, Inc. Subsequent to December 31, 2015, the Company exercised its contractual option to sell its ownership interest to Duke Energy Florida, Inc. contingent on regulatory approvals. The ultimate outcome of this matter cannot be determined at this time; however, no material impact on the Company's financial statements is expected.LLC.
At December 31, 20152017, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows:
| | Facility (Type) | Company Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP | Company Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP |
| | | (in millions) | | | (in millions) |
Plant Vogtle (nuclear) | | | | | | | | | | | | | | |
Units 1 and 2 | 45.7 | % | | $ | 3,503 |
| | $ | 2,084 |
| | $ | 63 |
| 45.7 | % | | $ | 3,564 |
| | $ | 2,141 |
| | $ | 70 |
|
Plant Hatch (nuclear) | 50.1 |
| | 1,230 |
| | 568 |
| | 90 |
| 50.1 |
| | 1,321 |
| | 595 |
| | 87 |
|
Plant Wansley (coal) | 53.5 |
| | 915 |
| | 290 |
| | 13 |
| 53.5 |
| | 1,053 |
| | 335 |
| | 72 |
|
Plant Scherer (coal) | | | | | | | | | | | | | | |
Units 1 and 2 | 8.4 |
| | 260 |
| | 86 |
| | 1 |
| 8.4 |
| | 261 |
| | 93 |
| | 8 |
|
Unit 3 | 75.0 |
| | 1,223 |
| | 433 |
| | 1 |
| 75.0 |
| | 1,232 |
| | 468 |
| | 26 |
|
Rocky Mountain (pumped storage) | 25.4 |
| | 181 |
| | 125 |
| | — |
| 25.4 |
| | 182 |
| | 132 |
| | — |
|
Intercession City (combustion-turbine) | 33.3 |
| | 13 |
| | 4 |
| | — |
| |
The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.
NOTES (continued)
Georgia Power Company 2017 Annual Report
The Company also owns 45.7% of Plant Vogtle Units 3 and 4, thatwhich are currently under construction.construction and had a CWIP balance of $3.3 billion as of December 31, 2017. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters – Rate Plans" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Federal – | | | | | | | | | | |
Current | $ | 515 |
| | $ | 295 |
| | $ | 277 |
| $ | 256 |
| | $ | 391 |
| | $ | 515 |
|
Deferred | 176 |
| | 366 |
| | 374 |
| 504 |
| | 319 |
| | 176 |
|
| 691 |
| | 661 |
| | 651 |
| 760 |
| | 710 |
| | 691 |
|
State – | | | | | | | | | | |
Current | 81 |
| | 82 |
| | (30 | ) | 116 |
| | 6 |
| | 81 |
|
Deferred | (3 | ) | | (14 | ) | | 102 |
| (46 | ) | | 64 |
| | (3 | ) |
| 78 |
| | 68 |
| | 72 |
| 70 |
| | 70 |
| | 78 |
|
Total | $ | 769 |
| | $ | 729 |
| | $ | 723 |
| $ | 830 |
| | $ | 780 |
| | $ | 769 |
|
NOTES (continued)
Georgia Power Company 20152017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Deferred tax liabilities – | | | | | | |
Accelerated depreciation | $ | 4,909 |
| | $ | 4,732 |
| $ | 3,540 |
| | $ | 5,266 |
|
Property basis differences | 943 |
| | 811 |
| — |
| | 957 |
|
Employee benefit obligations | 310 |
| | 329 |
| 287 |
| | 428 |
|
Under-recovered fuel costs | — |
| | 81 |
| |
Premium on reacquired debt | 61 |
| | 66 |
| 34 |
| | 56 |
|
Regulatory assets associated with employee benefit obligations | 528 |
| | 534 |
| |
Regulatory assets – | | | | |
Storm damage reserves | | 89 |
| | 83 |
|
Employee benefit obligations | | 348 |
| | 546 |
|
Asset retirement obligations | | 501 |
| | 726 |
|
Retired assets | | 30 |
| | 55 |
|
Asset retirement obligations | 706 |
| | 497 |
| 132 |
| | 182 |
|
Other | 187 |
| | 160 |
| 100 |
| | 83 |
|
Total | 7,644 |
| | 7,210 |
| 5,061 |
| | 8,382 |
|
Deferred tax assets – | | | | | | |
Federal effect of state deferred taxes | 150 |
| | 148 |
| 72 |
| | 173 |
|
Employee benefit obligations | 642 |
| | 642 |
| 423 |
| | 661 |
|
Other property basis differences | 88 |
| | 86 |
| |
Property basis differences | | 92 |
| | 105 |
|
Other deferred costs | 83 |
| | 86 |
| 69 |
| | 100 |
|
Cost of removal obligations | 6 |
| | 11 |
| |
State investment tax credit carryforward | 188 |
| | 152 |
| 318 |
| | 201 |
|
Federal tax credit carryforward | 3 |
| | 5 |
| 97 |
| | 84 |
|
Over-recovered fuel costs | 45 |
| | — |
| |
Unbilled fuel revenue | 47 |
| | 46 |
| 26 |
| | 47 |
|
Regulatory liabilities associated with asset retirement obligations | | 5 |
| | 33 |
|
Asset retirement obligations | 706 |
| | 497 |
| 631 |
| | 908 |
|
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | | 123 |
| | — |
|
Other | 59 |
| | 63 |
| 30 |
| | 70 |
|
Total | 2,017 |
| | 1,736 |
| 1,886 |
| | 2,382 |
|
Accumulated deferred income taxes | $ | 5,627 |
| | $ | 5,474 |
| $ | 3,175 |
| | $ | 6,000 |
|
On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentationThe implementation of deferred income taxes. The new guidance resulted in a reclassification from prepaid income taxes of $34 million to non-currentTax Reform Legislation significantly reduced accumulated deferred income taxes, in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information.
The application ofpartially offset by bonus depreciation provisions in current tax law hasof the Protecting Americans from Tax Hikes Act. Tax Reform Legislation also reduced tax-related regulatory assets and significantly increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014.tax-related regulatory liabilities.
At December 31, 2015,2017, tax-related regulatory assets to be recovered from customers were $683$521 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years and deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.law.
At December 31, 2015,2017, tax-related regulatory liabilities to be credited to customers were $105 million.$3.2 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and unamortized ITCs.law.
In accordance with regulatory requirements, deferred federal ITCs are deferred and, upon utilization, amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $10 million in 2015, $10 million in 2014,each of 2017, 2016, and $5 million in 2013.2015. State investment tax and other tax credits are recognized in the period in which the credits are claimed on the state income tax returngenerated and totaled $50 million in 2017, $42 million in 2016, and $33 million in 2015, $34 million in 2014, and $27 million in 2013.2015. At December 31, 2015,2017, the Company had $3$87 million in federal tax creditITC carryforwards that will expire by 20352037 and $188$318 million in state ITC carryforwards that will expire between 2020 and 2026.2028.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0% | | 35.0% | | 35.0% | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | 2.5 | | 2.2 | | 2.5 | 2.0 |
| | 2.1 |
| | 2.5 |
|
Non-deductible book depreciation | 1.2 | | 1.3 | | 1.3 | 0.7 |
| | 0.8 |
| | 1.2 |
|
AFUDC equity | (0.7) | | (0.8) | | (0.6) | (0.6 | ) | | (0.8 | ) | | (0.7 | ) |
Tax Reform Legislation | | (0.4 | ) | | — |
| | — |
|
Other | (0.4) | | (0.7) | | (0.4) | — |
| | (0.4 | ) | | (0.4 | ) |
Effective income tax rate | 37.6% | | 37.0% | | 37.8% | 36.7 | % | | 36.7 | % | | 37.6 | % |
The changesIn March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate are primarily the result of benefits related to emission allowances and state apportionment recorded in 2014.rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Unrecognized Tax Benefits
ChangesThe Company had no material unrecognized tax benefits as of December 31, 2017 and no material changes in unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Unrecognized tax benefits at beginning of year | $ | — |
| | $ | — |
| | $ | 23 |
|
Tax positions increase from prior periods | 3 |
| | — |
| | — |
|
Tax positions decrease from prior periods | — |
| | — |
| | (23 | ) |
Balance at end of year | $ | 3 |
| | $ | — |
| | $ | — |
|
The tax positions increase from prior periods for 2015 primarily relates to a graduated tax rate adjustment on the 2014 federal income tax return and will impact the Company's effective tax rate, if recognized. The tax positions decrease from prior periods for 2013 primarily relates to the Company's compliance with final U.S. Treasury regulations for a tax accounting method change for repairs.
These amounts are presented on a gross basis without considering the related federal or state income tax impact.any year presented.
The Company classifies interest on tax uncertainties as interest expense. Accruedexpense; however, the Company did not have any accrued interest or penalties for unrecognized tax benefits was immaterial for all periodsany year presented. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Securities Due Within One Year
A summary of scheduled maturities of long-term debtsecurities due within one year at December 31 was as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Senior notes | $ | 700 |
| | $ | 1,050 |
| $ | 750 |
| | $ | 450 |
|
Pollution control revenue bonds | 4 |
| | 98 |
| |
Capital lease | 8 |
| | 6 |
| |
Capital leases | | 11 |
| | 10 |
|
Other long-term debt
| | 100 |
| | — |
|
Unamortized debt issuance expense | — |
| | (4 | ) | (1 | ) | | — |
|
Total | $ | 712 |
| | $ | 1,150 |
| $ | 860 |
| | $ | 460 |
|
Maturities through 2022 applicable to total long-term debt are as follows: $861 million in 2018; $513 million in 2019; $1.0 billion in 2020; $375 million in 2021; and $518 million in 2022.
II-273Bank Term Loans
In June 2017, the Company entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, bearing interest based on one-month LIBOR. Also in June 2017, the Company borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by the Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of the Company's
NOTES (continued)
Georgia Power Company 20152017 Annual Report
Maturities through 2020 applicableexisting indebtedness and for working capital and other general corporate purposes, including the Company's continuous construction program.
In August 2017, the Company repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, the Company amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018. In December 2017, the Company repaid the remaining $250 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement.
At December 31, 2017, the Company had a total long-term debt are as follows: $712of $250 million in 2016; $459bank term loans outstanding. Subsequent to December 31, 2017, the Company repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively. At December 31, 2016, the Company had no bank term loans outstanding.
The outstanding bank loans as of December 31, 2017 had covenants that limited debt levels to 65% of total capitalization, as defined in 2017; $761 millionthe agreements. For purposes of these definitions, debt excludes certain hybrid securities. At December 31, 2017, the Company was in 2018; $512 million in 2019; and $49 million in 2020.compliance with its debt limits.
Senior Notes
In December 2015,March 2017, the Company issued $500$450 million aggregate principal amount of Series 2015A 1.95%2017A 2.00% Senior Notes due December 1, 2018. The proceeds were used to repay at maturity $250March 30, 2020 and $400 million aggregate principal amount of the Company's Series Z 5.25%2017B 3.25% Senior Notes due December 15, 2015,March 30, 2027. The proceeds were used to repay a portion of the Company's short-term indebtedness and for general corporate purposes, including the Company's continuous construction program.
In August 2017, the Company issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay the Company's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.
At December 31, 20152017 and 20142016, the Company had $6.3$7.1 billion and $6.9$6.2 billion of senior notes outstanding, respectively.respectively, which included senior notes due within one year. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $2.4 billion and $1.2$2.8 billion at both December 31, 20152017 and 2014, respectively.2016. As of December 31, 2015,2017, the Company's secured debt included borrowings of $2.2$2.6 billion guaranteed by the DOE and capital lease obligations.obligations of $154 million. As of December 31, 2014,2016, the Company's secured debt was related toincluded borrowings of $2.6 billion guaranteed by the DOE and capital lease obligations.obligations of $169 million. See Note 7 for additional information.
Seeand "DOE Loan Guarantee Borrowings" herein for additional information.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bondsbond obligations outstanding at both December 31, 20152017 and 20142016 was $1.8 billion and $1.6 billion, respectively.billion.
In May 2015,April 2017, the Company reoffered to the public $104.6purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), FirstFifth Series 2013, which had been previously1995. In October 2017, the Company remarketed these bonds to the public.
In August 2017, the Company purchased and held by the Company since 2013.
In August 2015, in connection with optional tenders, the Company repurchased and reoffered to the public $94.6$38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009 and $101997. In October 2017, the Company remarketed these bonds to the public.
Junior Subordinated Notes
At December 31, 2017, the Company had a total of $270 million of junior subordinated notes outstanding. At December 31, 2016, the Company had no junior subordinated notes outstanding.
In September 2017, the Company issued $270 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013.
In November 2015, the Company reoffered to the public $89.2 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2009 and $46 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1996, which had been previously repurchased and held by the Company since 2010.
Bank Term Loans
In March 2015, the Company entered into a $250 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR.2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used to redeem all outstanding shares of the Company's preferred and preference stock. See "Outstanding Classes of Capital Stock" herein for working capital and other general corporate purposes and the loan was repaid at maturity.additional information.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), the Company and the DOE entered into a loan guarantee agreement (Loanthe Loan Guarantee Agreement)Agreement in February 2014, under which the DOE agreed to guarantee the obligations of the Company under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, the Company, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and
NOTES (continued)
Georgia Power Company 2017 Annual Report
the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which the Company may make term loan borrowings through the FFB.
On July 27, 2017, the Company entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to the Company's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses).
Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, the Company will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) the Company's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
Proceeds of advances made under the FFB Credit Facility are used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (EligibleEligible Project Costs).Costs. Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46$3.46 billion.
On September 28, 2017, the DOE issued a conditional commitment to the Company for up to approximately $1.67 billion. of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.
All borrowings under the FFB Credit Facility are full recourse to the Company, and the Company is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. The Company's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant
NOTES (continued)
Georgia Power Company 2015 Annual Report
Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on the Company's ability to grant liens on other property.
Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
In February 2014, the Company made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicableaddition to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, the Company incurred issuance costs of approximately $66 million, which are being amortized over the life of the borrowings under the FFB Credit Facility.
In December 2014, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million. The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044.
In June and December 2015, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600 million and $400 million, respectively. The interest rate applicable to the $600 million principal amount is 3.283% and the interest rate applicable to the $400 million principal amount is 3.072%, both for an interest period that extends to 2044.
Futureconditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.
Upon satisfaction of all conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.
At both December 31, 2017 and 2016, the Company had $2.6 billion of borrowings outstanding under the FFB Credit Facility.
Under the Loan Guarantee Agreement, the Company is subject to customary borrower affirmative and negative covenants and events of default. In addition, the Company is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if the Company does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by the Company not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by the Company if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or the Company's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if the Company discontinues construction of Plant Vogtle Units 3 and 4, the Company would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by the Company under the Guarantee Settlement Agreement. The Company also may
NOTES (continued)
Georgia Power Company 2017 Annual Report
voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note,Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume the Company's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of the Company's ownership interest in Plant Vogtle Units 3 and 4.
Capital Leases
Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 20152017 and 2014,2016, the Company had a capital lease asset for its corporate headquarters building of $61 million, with accumulated depreciation at December 31, 20152017 and 20142016 of $26$39 million and $21$33 million, respectively. At December 31, 20152017 and 20142016, the capitalized lease obligation was $35$22 million and $4028 million, respectively, with an annual interest rate of 7.9% for both years.. For ratemaking purposes, the Georgia PSC has allowed only the lease payments in cost of service.service with no return on the capital lease asset. The difference between the accrued expensedepreciation and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expenserecovered as operating expenses as ordered by the Georgia PSC. The annual operating expense incurred for allthis capital leaseslease was not material for any year presented.
At December 31, 2015,2017 and 2016, the Company had capital lease assets related to two PPAs with Southern Power of $144 million and corresponding obligations of $149 million, respectively, with accumulated amortization at December 31, 2017 and $148 million, respectively, for two affiliate PPAs that became effective in 2015. Contractual lease payments, including imputed interest,2016 of $20$29 million and capital$19 million, respectively. At December 31, 2017 and 2016, the related capitalized lease asset amortization of $10obligations were $132 million were included in purchased power, affiliates expense in 2015.and $141 million, respectively. The
NOTES (continued)
Georgia Power Company 2015 Annual Report
annual imputed interest rates will range from 13%10% to 14%12% for these two capital lease PPAs over their term.PPAs. For ratemaking purposes, the Georgia PSC has allowedincluded the capital lease asset amortization in cost of service and the imputed interest in the Company's cost of debt. See Note 1 under "Affiliate Transactions" and Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Assets Subject to Lien
See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of the Company that are secured by a first priority lien on (i) the Company’sCompany's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4.
See "Capital Leases" above for information regarding certain assets held under capital leases.
Outstanding Classes of Capital Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its common stock outstanding. In October 2017, the Company redeemed all 1.8 million shares ($45 million aggregate liquidation amount) of its 6.125% Series Class A Preferred Stock and 2.25 millionshares ($225 millionaggregate liquidation amount) of its 6.50% Series 2007A Preference Stock. No shares of preferred stock, Class A preferred stock, or preference stock and common stock outstanding. The Company's Class A preferred stock ranks senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Thewere outstanding series of the Class A preferred stock is subject to redemption at the option of the Company at any time at a redemption price equal to 100% of the par value. In addition, on or after October 1, 2017, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the par value. With respect to any redemption of the preference stock prior to October 1, 2017, the redemption price includes a make-whole premium based on the present value of the liquidation amount and future dividends through the first par redemption date.December 31, 2017.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Bank Credit Arrangements
At December 31, 2015,2017, the Company had a $1.75 billion committed credit arrangement with banks, of which $1.73 billion was unused. These credit arrangements expire in 2020.
In August 2015,May 2017, the Company amended and restated its multi-year credit arrangement which, among other things, extended the maturity date from 20182020 to 2020. The2022.
This bank credit arrangement requires payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company.
This bank credit arrangement contains a covenant that limits the Company's debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities. At December 31, 2017, the Company increased its borrowing ability by $150 million under its facility maturingwas in 2020 and terminated its aggregate $150 million facilities maturing in 2016.compliance with the debt limit covenant.
Subject to applicable market conditions, the Company expects to renew this bank credit arrangement, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitments thereunder. This bank credit arrangement requires payment
The bank credit arrangement contains a covenant that limits the Company's debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes certain hybrid securities.
NOTES (continued)
Georgia Power Company 2017 Annual Report
A portion of the $1.73 billion unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 20152017 was $872 million.$550 million as compared to $868 million at December 31, 2016. In addition, at December 31, 2015,2017, the Company had $69$469 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangementsarrangement described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans areis included in notes payable in the balance sheets.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Details of short-term borrowings outstanding were as follows:
| | | Short-term Debt at the End of the Period | Short-term Debt at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate | Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | | (in millions) | | |
December 31, 2015: | | | | |
December 31, 2017: | | | | |
Short-term bank debt | | $ | 150 |
| | 2.2 | % |
December 31, 2016: | | | | |
Commercial paper | $ | 158 |
| | 0.6 | % | $ | 392 |
| | 1.1 | % |
December 31, 2014: | | | | |
Commercial paper | $ | 156 |
| | 0.3 | % | |
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2015, 2014,2017, 2016, and 2013,2015, the Company incurred fuel expense of $2.0$1.7 billion, $2.5$1.8 billion, and $2.3$2.0 billion,, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. On December 15, 2015, the Company's natural gas hedging program was revised and approved by the Georgia PSC.
The Company has commitments regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Portions of the capacity payments relate to costs in excess of MEAG Power's Plant Vogtle Units 1 and 2 allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power, non-affiliates in the statements of income. Capacity payments totaled $10$9 million, $19$11 million, and $2710 million in 2015, 2014,2017, 2016, and 2013,2015, respectively.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
The Company has also entered into various long-term PPAs, some of which are accounted for as capital or operating leases. Total capacity expense under PPAs accounted for as operating leases was $203$199 million, $167$217 million, and $162203 million for 2017, 2016, and 2015, 2014,respectively. Contingent rent expense under energy-only solar PPAs of $73 million, $39 million, and 2013, respectively.$8 million for 2017, 2016, and 2015, respectively, was recognized as services were performed. Estimated total long-term obligations at December 31, 20152017 were as follows:
| | | Affiliate Capital Leases | | Affiliate Operating Leases | | Non-Affiliate Operating Leases (4) | | Vogtle Units 1 and 2 Capacity Payments | | Total ($) | Affiliate Capital Leases | | Affiliate Operating Leases | | Non-Affiliate Operating Leases | | Vogtle Units 1 and 2 Capacity Payments | | Total |
| (in millions) | (in millions) |
2016 | $ | 22 |
| | $ | 99 |
| | $ | 115 |
| | $ | 10 |
| | $ | 246 |
| |
2017 | 22 |
| | 71 |
| | 123 |
| | 8 |
| | 224 |
| |
2018 | 22 |
| | 62 |
| | 126 |
| | 7 |
| | 217 |
| $ | 23 |
| | $ | 62 |
| | $ | 127 |
| | $ | 7 |
| | $ | 219 |
|
2019 | 23 |
| | 63 |
| | 127 |
| | 8 |
| | 221 |
| 23 |
| | 63 |
| | 128 |
| | 6 |
| | 220 |
|
2020 | 23 |
| | 64 |
| | 123 |
| | 4 |
| | 214 |
| 23 |
| | 65 |
| | 124 |
| | 4 |
| | 216 |
|
2021 and thereafter | 227 |
| | 538 |
| | 1,007 |
| | 47 |
| | 1,819 |
| |
2021 | | 24 |
| | 66 |
| | 125 |
| | 5 |
| | 220 |
|
2022 | | 24 |
| | 67 |
| | 126 |
| | 4 |
| | 221 |
|
2023 and thereafter | | 182 |
| | 412 |
| | 773 |
| | 38 |
| | 1,405 |
|
Total | $ | 339 |
| | $ | 897 |
| | $ | 1,621 |
| | $ | 84 |
| | $ | 2,941 |
| $ | 299 |
| | $ | 735 |
| | $ | 1,403 |
| | $ | 64 |
| | $ | 2,501 |
|
Less: amounts representing executory costs(1)(a) | 54 |
| | | | | | | | | 45 |
| | | | | | | | |
Net minimum lease payments | 285 |
| | | | | | | | | 254 |
| | | | | | | | |
Less: amounts representing interest(2)(b) | 84 |
| | | | | | | | | 120 |
| | | | | | | | |
Present value of net minimum lease payments(3) | $ | 201 |
| | | | | | | | | $ | 134 |
| | | | | | | | |
| |
(1)(a) | Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments. |
| |
(2)(b) | Amount necessary to reduce minimum lease payments to present value calculated at the Company'sCalculated using an adjusted incremental borrowing rate at the inception of the leases. |
| |
(3) | Once service commenced under the PPAs beginning in 2015, the Company recognized capital lease assets and capital lease obligations totaling $149 million, being the lesser of the estimated fair value of the lease property orto reduce the present value of the net minimum lease payments. |
| |
(4) | A total of $304 million of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action.payments to fair value. |
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
In addition to the PPAThe Company has entered into operating leases discussed above,with Southern Linc and third parties for the use of cellular tower space. Substantially all of these agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years. The Company has also entered into rental agreements for facilities, railcars, and other operating lease agreementsequipment with various terms and expiration dates. Total rent expense was $29$31 million, for 2015, $28 million for 2014, and $3229 million for 2017, 2016, and 20132015., respectively. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
As of December 31, 2015,2017, estimated minimum lease payments under operating leases were as follows:
| | | Minimum Lease Payments | Minimum Lease Payments |
| Railcars | | Other | | Total | Affiliate Operating Leases(a) | | Non-Affiliate Operating Leases (b) | | Total |
| (in millions) | (in millions) |
2016 | $ | 15 |
| | $ | 8 |
| | $ | 23 |
| |
2017 | 10 |
| | 8 |
| | 18 |
| |
2018 | 5 |
| | 7 |
| | 12 |
| $ | 10 |
| | $ | 14 |
| | $ | 24 |
|
2019 | 1 |
| | 7 |
| | 8 |
| 11 |
| | 11 |
| | 22 |
|
2020 | 1 |
| | 6 |
| | 7 |
| 11 |
| | 9 |
| | 20 |
|
2021 and thereafter | 3 |
| | 13 |
| | 16 |
| |
2021 | | 9 |
| | 8 |
| | 17 |
|
2022 | | 8 |
| | 6 |
| | 14 |
|
2023 and thereafter | | 33 |
| | 11 |
| | 44 |
|
Total | $ | 35 |
| | $ | 49 |
| | $ | 84 |
| $ | 82 |
| | $ | 59 |
| | $ | 141 |
|
| |
(a) | Includes operating leases for cellular tower space. |
| |
(b) | Includes operating leases for cellular tower space, facilities, railcars, and other equipment. |
Railcar minimum lease payments are disclosed at 100% of railcar lease obligations; however, a portion of these obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the railcar leases are recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates.
In addition to the above rental commitments, the Company has obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $32 million. At the termination of the leases, the lesseeCompany may either renew the lease, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations.
Guarantees
Alabama Power has guaranteed the obligations of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information.
In addition, in 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017.2018. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million.
As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to railcar leases.
8. STOCK COMPENSATION
Stock-Based Compensation
Stock-based compensation primarily in the form of Southern Company stock optionsperformance share units and performance sharerestricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2015,2017, there were 1,002895 current and former employees participating in the stock option, and performance share unit, and restricted stock unit programs.
Stock Options
Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualified stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for
NOTES (continued)
Georgia Power Company 20152017 Annual Report
those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units.
For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 2,034,150 shares and 1,509,662 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93, respectively.
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $9 million, $19 million, and $16 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $4 million, $7 million, and $6 million for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, the aggregate intrinsic value for the options outstanding and options exercisable was $45 million and $38 million, respectively.
Performance Share Units
From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period which equates to the requisite service period for accounting purposes.period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
The performance goal for allSouthern Company issues performance share units issued from 2010 through 2014 waswith performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For thesepeers, performance share units at the end of three years, active employees receive shareswith performance goals based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service duringcumulative earnings per share (EPS) over the performance period, prior to retirement. and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. TheEmployees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee.retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, employees of the Company were granted performance share units of 236,804, 176,224,138,102, 261,434, and 161,240,236,804, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014,2017, 2016, and 2013,2015, determined using a Monte Carlo simulation model to estimate the TSR of Southern
NOTES (continued)
Georgia Power Company 2015 Annual Report
Company's stock among the industry peers over the performance period, was $46.41, $37.54,$49.27, $45.17, and $40.50,$46.41, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $47.78.$49.22, $48.84, and $47.78, respectively.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, total compensation cost for performance share units recognized in income was $10 million, $15 million, $6 million, and $6$15 million, respectively, with the related tax benefit also recognized in income of $4 million, $6 million, $2 million, and $2$6 million, respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees areis recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015, there was $42017, $3 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 1921 months.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees
NOTES (continued)
Georgia Power Company 2017 Annual Report
become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
For the year ended December 31, 2017, employees of the Company were granted 59,218 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.22.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $3 million with the related tax benefit also recognized in income of $1 million. As of December 31, 2017, $1 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.
Stock Options
In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017, all compensation cost related to stock option awards has been recognized.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $13 million, $18 million, and $9 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $5 million, $7 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017, the aggregate intrinsic value for the options outstanding and exercisable was $30 million.
9. NUCLEAR INSURANCE
Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Hatch and Plant Vogtle Units 1 and 2. The Act provides funds up to $13.5$13.4 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375$450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests in all licensed reactors, is $247 million per incident, but not more than an aggregate of $37 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements.
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. In April 2014, NEIL introduced a new excess non-nuclear policyand policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years.exhausted. The Company purchases limits based on the projected full cost of replacement power, subject to ownership limitations. Each facilitylimitations, and has elected a 12-week deductible waiting period.period for each facility.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
NOTES (continued)
Georgia Power Company 2017 Annual Report
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company as of December 31, 2017 under the NEIL policies would be $84$81 million.
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
NOTES (continued)
Georgia Power Company 2015 Annual Report
10. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
NOTES (continued)
Georgia Power Company 2017 Annual Report
As of December 31, 20152017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
| $ | — |
| | $ | 6 |
| | $ | — |
| | $ | 6 |
|
Interest rate derivatives | — |
| | 5 |
| | — |
| | 5 |
| |
Nuclear decommissioning trusts:(*) | | | | | | | | |
Nuclear decommissioning trusts:(*) | | | | | | | | |
Domestic equity | 182 |
| | 1 |
| | — |
| | 183 |
| 248 |
| | 1 |
| | — |
| | 249 |
|
Foreign equity | — |
| | 113 |
| | — |
| | 113 |
| — |
| | 166 |
| | — |
| | 166 |
|
U.S. Treasury and government agency securities | — |
| | 125 |
| | — |
| | 125 |
| — |
| | 227 |
| | — |
| | 227 |
|
Municipal bonds | — |
| | 64 |
| | — |
| | 64 |
| — |
| | 68 |
| | — |
| | 68 |
|
Corporate bonds | — |
| | 143 |
| | — |
| | 143 |
| — |
| | 155 |
| | — |
| | 155 |
|
Mortgage and asset backed securities | — |
| | 127 |
| | — |
| | 127 |
| — |
| | 40 |
| | — |
| | 40 |
|
Other | 16 |
| | 4 |
| | — |
| | 20 |
| 12 |
| | 12 |
| | — |
| | 24 |
|
Cash equivalents | 63 |
| | — |
| | — |
| | 63 |
| 690 |
| | — |
| | — |
| | 690 |
|
Total | $ | 261 |
| | $ | 584 |
| | $ | — |
| | $ | 845 |
| $ | 950 |
| | $ | 675 |
| | $ | — |
| | $ | 1,625 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | 15 |
| $ | — |
| | $ | 19 |
| | $ | — |
| | $ | 19 |
|
Interest rate derivatives | — |
| | 6 |
| | — |
| | 6 |
| — |
| | 5 |
| | — |
| | 5 |
|
Total | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | 21 |
| $ | — |
| | $ | 24 |
| | $ | — |
| | $ | 24 |
|
| |
(*) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending pool.program. See Note 1 under "Nuclear Decommissioning" for additional information. |
NOTES (continued)
Georgia Power Company 20152017 Annual Report
As of December 31, 2014,2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
| $ | — |
| | $ | 44 |
| | $ | — |
| | $ | 44 |
|
Interest rate derivatives | — |
| | 6 |
| | — |
| | 6 |
| — |
| | 2 |
| | — |
| | 2 |
|
Nuclear decommissioning trusts:(*) | | | | | | | | |
Nuclear decommissioning trusts:(*) | | | | | | | | |
Domestic equity | 180 |
| | 2 |
| | — |
| | 182 |
| 204 |
| | 1 |
| | — |
| | 205 |
|
Foreign equity | — |
| | 121 |
|
| — |
| | 121 |
| — |
| | 121 |
|
| — |
| | 121 |
|
U.S. Treasury and government agency securities | — |
| | 96 |
| | — |
| | 96 |
| — |
| | 71 |
| | — |
| | 71 |
|
Municipal bonds | — |
| | 62 |
| | — |
| | 62 |
| — |
| | 73 |
| | — |
| | 73 |
|
Corporate bonds | — |
| | 188 |
| | — |
| | 188 |
| — |
| | 164 |
| | — |
| | 164 |
|
Mortgage and asset backed securities | — |
| | 121 |
| | — |
| | 121 |
| — |
| | 164 |
| | — |
| | 164 |
|
Other | 11 |
| | 8 |
| | — |
| | 19 |
| 11 |
| | 5 |
| | — |
| | 16 |
|
Total | $ | 191 |
| | $ | 611 |
| | $ | — |
| | $ | 802 |
| $ | 215 |
| | $ | 645 |
| | $ | — |
| | $ | 860 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 27 |
| | $ | — |
| | $ | 27 |
| $ | — |
| | $ | 8 |
| | $ | — |
| | $ | 8 |
|
Interest rate derivatives | — |
| | 14 |
| | — |
| | 14 |
| — |
| | 3 |
| | — |
| | 3 |
|
Total | $ | — |
| | $ | 41 |
| | $ | — |
| | $ | 41 |
| $ | — |
| | $ | 11 |
| | $ | — |
| | $ | 11 |
|
| |
(*) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, currencies, and payables related to pending investment purchases and the securities lending pool.program. See Note 1 under "Nuclear Decommissioning" for additional information. |
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflectreflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 11 for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 under "Nuclear Decommissioning" for additional information.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
The Company early adopted ASU 2015-07 effective December 31, 2015 on a retrospective basis. The guidance removed certain disclosures required for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. As of December 31, 2015 and 2014, the Company had no investments measured at net asset value as a practical expedient.
As of December 31, 20152017 and 20142016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2015 | $ | 10,145 |
| | $ | 10,480 |
|
2014 | $ | 9,673 |
| | $ | 10,552 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 11,777 |
| | $ | 12,531 |
|
2016 | $ | 10,516 |
| | $ | 11,034 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on current rates available to the Company.
11. DERIVATIVES
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’sCompany's policies in areas such as counterparty exposure and risk management practices. The Company’sCompany's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. The Company manages a fuel-hedging program implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Effective January 1, 2016, the Georgia PSC approved changes to the Company's hedging program allowing it to use an array of derivative instruments within a 48-month time horizon.
Energy-related derivative contracts are accounted for under one of two methods:
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’sCompany's fuel-hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 2015,2017, the net volume of energy-related derivative contracts for natural gas positions totaled 50163 million mmBtu, all of which expire by 2017,2021, which is the longest hedge date.
In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 410 million mmBtu for the Company.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Interest Rate Derivatives
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or
NOTES (continued)
Georgia Power Company 2017 Annual Report
losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. At December 31, 2017, there were no cash flow hedges outstanding. Derivatives related to fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains and losses and the hedged items' fair value gains and losses attributable to interest rate risk are both recorded directly to earnings, providing an offset, with any differences representing ineffectiveness.
At December 31, 20152017, the following interest rate derivatives were outstanding:
| | | Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2015 | |
| (in millions) | | (in millions) | |
Cash Flow Hedges of Existing Debt | | | |
| $ | 250 |
| | 3-month LIBOR + 0.32% | | 0.75% | | March 2016 | | $ | — |
| Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2017 |
| 200 |
| | 3-month LIBOR + 0.40% | | 1.01% | | August 2016 | | — |
| (in millions) | | (in millions) |
Fair Value Hedges of Existing Debt | | | | | | |
| 250 |
| | 5.40% | | 3-month LIBOR + 4.02% | | June 2018 | | 1 |
| $ | 250 |
| | 5.40% | | 3-month LIBOR + 4.02% | | June 2018 | | $ | — |
|
| 200 |
| | 4.25% | | 3-month LIBOR + 2.46% | | December 2019 | | 2 |
| 500 |
| | 1.95% | | 3-month LIBOR + 0.76% | | December 2018 | | (3 | ) |
| 500 |
| | 1.95% | | 3-month LIBOR + .76% | | December 2018 | | (3 | ) | 200 |
| | 4.25% | | 3-month LIBOR + 2.46% | | December 2019 | | (1 | ) |
Total | $ | 1,400 |
| | $ | — |
| $ | 950 |
| | $ | (4 | ) |
The estimated pre-tax gains (losses) related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 20162018 are $4total $(4) million. The Company has deferredDeferred gains and losses related to interest rate derivative settlements of cash flow hedges that are expected to be amortized into earnings through 2037.
NOTES (continued)
Georgia Power Company 2015 Annual Report
Derivative Financial Statement Presentation and Amounts
At December 31, 2015 and 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | 2 |
| | $ | 6 |
| | Liabilities from risk management activities | $ | 12 |
| | $ | 23 |
|
| Other deferred charges and assets | — |
| | 1 |
| | Other deferred credits and liabilities | 3 |
| | 4 |
|
Total derivatives designated as hedging instruments for regulatory purposes | | $ | 2 |
| | $ | 7 |
| | | $ | 15 |
| | $ | 27 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges |
|
| | | | | | | |
Interest rate derivatives: | Other current assets | $ | 5 |
| | $ | 5 |
| | Liabilities from risk management activities | $ | — |
| | $ | 9 |
|
| Other deferred charges and assets | — |
| | 1 |
| | Other deferred credits and liabilities | 6 |
| | 5 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges |
| $ | 5 |
| | $ | 6 |
| |
| $ | 6 |
| | $ | 14 |
|
Total |
| $ | 7 |
| | $ | 13 |
| |
| $ | 21 |
| | $ | 41 |
|
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014.
The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of theseCompany enters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-relatedFair value amounts of derivative contractsassets and interest rate derivative contracts at December 31, 2015 and 2014liabilities on the balance sheets are presented innet to the following tables.extent that there are netting arrangements or similar agreements with the counterparties.
|
| | | | | | | | | | | | | | | | |
Fair Value |
Assets | 2015 |
| | 2014 |
| | Liabilities | 2015 |
| | 2014 |
|
| (in millions) | | | (in millions) |
Energy-related derivatives presented in the Balance Sheet (a) | $ | 2 |
| | $ | 7 |
| | Energy-related derivatives presented in the Balance Sheet (a) | $ | 15 |
| | $ | 27 |
|
Gross amounts not offset in the Balance Sheet (b) | (2 | ) | | (7 | ) | | Gross amounts not offset in the Balance Sheet (b) | (2 | ) | | (7 | ) |
Net energy-related derivative assets | $ | — |
| | $ | — |
| | Net energy-related derivative liabilities | $ | 13 |
| | $ | 20 |
|
Interest rate derivatives presented in the Balance Sheet (a) | $ | 5 |
| | $ | 6 |
| | Interest rate derivatives presented in the Balance Sheet (a) | $ | 6 |
| | $ | 14 |
|
Gross amounts not offset in the Balance Sheet (b) | (4 | ) | | (6 | ) | | Gross amounts not offset in the Balance Sheet (b) | (4 | ) | | (6 | ) |
Net interest rate derivative assets | $ | 1 |
| | $ | — |
| | Net interest rate derivative liabilities | $ | 2 |
| | $ | 8 |
|
| |
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
NOTES (continued)
Georgia Power Company 20152017 Annual Report
At December 31, 20152017 and 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | |
| 2017 | | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 2 |
| $ | (9 | ) | | $ | 30 |
| $ | 1 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| (10 | ) | | 14 |
| 7 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 6 |
| $ | (19 | ) | | $ | 44 |
| $ | 8 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | $ | — |
| $ | (4 | ) | | $ | 2 |
| $ | — |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| (1 | ) | | — |
| 3 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | (5 | ) | | $ | 2 |
| $ | 3 |
|
Gross amounts recognized | $ | 6 |
| $ | (24 | ) | | $ | 46 |
| $ | 11 |
|
Gross amounts offset | $ | (6 | ) | $ | 6 |
| | $ | (8 | ) | $ | (8 | ) |
Net amounts recognized in the Balance Sheets | $ | — |
| $ | (18 | ) | | $ | 38 |
| $ | 3 |
|
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and 2016.
At December 31, 2017 and 20142016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instrumentsderivatives designated as regulatory hedging instruments and deferred were as follows:
| | | Unrealized Losses | | Unrealized Gains | Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (12 | ) | | $ | (23 | ) | | Other regulatory liabilities, current | $ | 2 |
| | $ | 6 |
| Other regulatory assets, current | $ | (7 | ) | | $ | — |
| | Other regulatory liabilities, current | $ | — |
| | $ | 29 |
|
| Other regulatory assets, deferred | (3 | ) | | (4 | ) | | Other deferred credits and liabilities | — |
| | 1 |
| Other regulatory assets, deferred | (6 | ) | | — |
| | Other deferred credits and liabilities | — |
| | 7 |
|
Total energy-related derivative gains (losses) | | $ | (15 | ) | | $ | (27 | ) | | $ | 2 |
| | $ | 7 |
| | $ | (13 | ) | | $ | — |
| | $ | — |
| | $ | 36 |
|
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
| | Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | | | | | | | Amount | | | | | | | | Amount |
Derivative Category | 2015 | | 2014 | | 2013 | | Statements of Income Location | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 | | Statements of Income Location | 2017 | | 2016 | | 2015 |
| (in millions) | | | (in millions) | (in millions) | | | (in millions) |
Interest rate derivatives | $ | (15 | ) | | $ | (8 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) | | $ | (3 | ) | $ | 1 |
| | $ | — |
| | $ | (15 | ) | | Interest expense, net of amounts capitalized | $ | (4 | ) | | $ | (4 | ) | | $ | (3 | ) |
NOTES (continued)
Georgia Power Company 2017 Annual Report
For the years ended December 31, 20152017, 2016, and 2014,2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for the Company. Furthermore, the pre-tax effect of interest rate derivatives designated as fair value hedging instruments on the Company's statements of income were offset by changes to the carrying value of long-term debt. The gains and losses related to interest rate derivative settlements of fair value hedges are recorded directly to earnings.
There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was immaterial for all years presented.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 20152017, the Company'sCompany had no collateral posted with its derivative counterparties was immaterial.to satisfy these arrangements.
At December 31, 2015,2017, the fair value of derivative liabilities with contingent features was $1$2 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $52$12 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES (continued)
Georgia Power Company 20152017 Annual Report
12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preferred and Preference Stock |
| (in millions) |
March 2015 | $ | 1,978 |
| | $ | 454 |
| | $ | 236 |
|
June 2015 | 2,016 |
| | 554 |
| | 277 |
|
September 2015 | 2,691 |
| | 964 |
| | 551 |
|
December 2015 | 1,641 |
| | 376 |
| | 196 |
|
| | | | | |
March 2014 | $ | 2,269 |
| | $ | 516 |
| | $ | 266 |
|
June 2014 | 2,186 |
| | 572 |
| | 311 |
|
September 2014 | 2,631 |
| | 920 |
| | 525 |
|
December 2014 | 1,902 |
| | 288 |
| | 123 |
|
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preferred and Preference Stock |
| (in millions) |
March 2017 | $ | 1,832 |
| | $ | 501 |
| | $ | 260 |
|
June 2017 | 2,048 |
| | 639 |
| | 347 |
|
September 2017 | 2,546 |
| | 1,034 |
| | 580 |
|
December 2017 | 1,884 |
| | 470 |
| | 227 |
|
| | | | | |
March 2016 | $ | 1,872 |
| | $ | 509 |
| | $ | 269 |
|
June 2016 | 2,051 |
| | 656 |
| | 349 |
|
September 2016 | 2,698 |
| | 1,054 |
| | 599 |
|
December 2016 | 1,762 |
| | 258 |
| | 113 |
|
The Company's business is influenced by seasonal weather conditions.
SELECTED FINANCIAL AND OPERATING DATA 2011-20152013-2017
Georgia Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 8,326 |
| | $ | 8,988 |
| | $ | 8,274 |
| | $ | 7,998 |
| | $ | 8,800 |
| $ | 8,310 |
| | $ | 8,383 |
| | $ | 8,326 |
| | $ | 8,988 |
| | $ | 8,274 |
|
Net Income After Dividends on Preferred and Preference Stock (in millions) | $ | 1,260 |
| | $ | 1,225 |
| | $ | 1,174 |
| | $ | 1,168 |
| | $ | 1,145 |
| $ | 1,414 |
| | $ | 1,330 |
| | $ | 1,260 |
| | $ | 1,225 |
| | $ | 1,174 |
|
Cash Dividends on Common Stock (in millions) | $ | 1,034 |
| | $ | 954 |
| | $ | 907 |
| | $ | 983 |
| | $ | 1,096 |
| $ | 1,281 |
| | $ | 1,305 |
| | $ | 1,034 |
| | $ | 954 |
| | $ | 907 |
|
Return on Average Common Equity (percent) | 11.92 |
| | 12.24 |
| | 12.45 |
| | 12.76 |
| | 12.89 |
| 12.15 |
| | 12.05 |
| | 11.92 |
| | 12.24 |
| | 12.45 |
|
Total Assets (in millions)(a)(b) | $ | 32,865 |
| | $ | 30,872 |
| | $ | 28,776 |
| | $ | 28,618 |
| | $ | 27,045 |
| $ | 36,779 |
| | $ | 34,835 |
| | $ | 32,865 |
| | $ | 30,872 |
| | $ | 28,776 |
|
Gross Property Additions (in millions) | $ | 2,332 |
| | $ | 2,146 |
| | $ | 1,906 |
| | $ | 1,838 |
| | $ | 1,981 |
| $ | 1,080 |
| | $ | 2,314 |
| | $ | 2,332 |
| | $ | 2,146 |
| | $ | 1,906 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 10,719 |
| | $ | 10,421 |
| | $ | 9,591 |
| | $ | 9,273 |
| | $ | 9,023 |
| $ | 11,931 |
| | $ | 11,356 |
| | $ | 10,719 |
| | $ | 10,421 |
| | $ | 9,591 |
|
Preferred and preference stock | 266 |
| | 266 |
| | 266 |
| | 266 |
| | 266 |
| — |
| | 266 |
| | 266 |
| | 266 |
| | 266 |
|
Long-term debt(a) | 9,616 |
| | 8,563 |
| | 8,571 |
| | 7,928 |
| | 7,944 |
| 11,073 |
| | 10,225 |
| | 9,616 |
| | 8,563 |
| | 8,571 |
|
Total (excluding amounts due within one year) | $ | 20,601 |
| | $ | 19,250 |
| | $ | 18,428 |
| | $ | 17,467 |
| | $ | 17,233 |
| $ | 23,004 |
| | $ | 21,847 |
| | $ | 20,601 |
| | $ | 19,250 |
| | $ | 18,428 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 52.0 |
| | 54.1 |
| | 52.0 |
| | 53.1 |
| | 52.4 |
| 51.9 |
| | 52.0 |
| | 52.0 |
| | 54.1 |
| | 52.0 |
|
Preferred and preference stock | 1.3 |
| | 1.4 |
| | 1.4 |
| | 1.5 |
| | 1.5 |
| — |
| | 1.2 |
| | 1.3 |
| | 1.4 |
| | 1.4 |
|
Long-term debt(a) | 46.7 |
| | 44.5 |
| | 46.6 |
| | 45.4 |
| | 46.1 |
| 48.1 |
| | 46.8 |
| | 46.7 |
| | 44.5 |
| | 46.6 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Customers (year-end): | | | | | | | | | | | | | | | | | | |
Residential | 2,127,658 |
| | 2,102,673 |
| | 2,080,358 |
| | 2,062,040 |
| | 2,047,390 |
| 2,185,782 |
| | 2,155,945 |
| | 2,127,658 |
| | 2,102,673 |
| | 2,080,358 |
|
Commercial(c) | 304,179 |
| | 301,246 |
| | 298,420 |
| | 296,397 |
| | 295,288 |
| 308,939 |
| | 305,488 |
| | 302,891 |
| | 300,186 |
| | 297,493 |
|
Industrial(c) | 9,141 |
| | 9,132 |
| | 9,136 |
| | 9,143 |
| | 9,134 |
| 10,644 |
| | 10,537 |
| | 10,429 |
| | 10,192 |
| | 10,063 |
|
Other | 9,261 |
| | 9,003 |
| | 8,623 |
| | 7,724 |
| | 7,521 |
| 9,766 |
| | 9,585 |
| | 9,261 |
| | 9,003 |
| | 8,623 |
|
Total | 2,450,239 |
| | 2,422,054 |
| | 2,396,537 |
| | 2,375,304 |
| | 2,359,333 |
| 2,515,131 |
| | 2,481,555 |
| | 2,450,239 |
| | 2,422,054 |
| | 2,396,537 |
|
Employees (year-end) | 7,989 |
| | 7,909 |
| | 7,886 |
| | 8,094 |
| | 8,310 |
| 6,986 |
| | 7,527 |
| | 7,989 |
| | 7,909 |
| | 7,886 |
|
|
| |
(a) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $124 million $62 million, $67 million, and $75$62 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b) | A reclassification of deferred tax assets from Total Assets of $34 million $68 million, $117 million, and $31$68 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-17. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(c) | A reclassification of customers from commercial to industrial is reflected for years 2011-20132013-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material. |
SELECTED FINANCIAL AND OPERATING DATA 2013-2017 (continued)
Georgia Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 3,236 |
| | $ | 3,318 |
| | $ | 3,240 |
| | $ | 3,350 |
| | $ | 3,058 |
|
Commercial | 3,092 |
| | 3,077 |
| | 3,094 |
| | 3,271 |
| | 3,077 |
|
Industrial | 1,321 |
| | 1,291 |
| | 1,305 |
| | 1,525 |
| | 1,391 |
|
Other | 89 |
| | 86 |
| | 88 |
| | 94 |
| | 94 |
|
Total retail | 7,738 |
| | 7,772 |
| | 7,727 |
| | 8,240 |
| | 7,620 |
|
Wholesale — non-affiliates | 163 |
| | 175 |
| | 215 |
| | 335 |
| | 281 |
|
Wholesale — affiliates | 26 |
| | 42 |
| | 20 |
| | 42 |
| | 20 |
|
Total revenues from sales of electricity | 7,927 |
| | 7,989 |
| | 7,962 |
| | 8,617 |
| | 7,921 |
|
Other revenues | 383 |
| | 394 |
| | 364 |
| | 371 |
| | 353 |
|
Total | $ | 8,310 |
| | $ | 8,383 |
| | $ | 8,326 |
| | $ | 8,988 |
| | $ | 8,274 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 26,144 |
| | 27,585 |
| | 26,649 |
| | 27,132 |
| | 25,479 |
|
Commercial | 32,155 |
| | 32,932 |
| | 32,719 |
| | 32,426 |
| | 31,984 |
|
Industrial | 23,518 |
| | 23,746 |
| | 23,805 |
| | 23,549 |
| | 23,087 |
|
Other | 584 |
| | 610 |
| | 632 |
| | 633 |
| | 630 |
|
Total retail | 82,401 |
| | 84,873 |
| | 83,805 |
| | 83,740 |
| | 81,180 |
|
Wholesale — non-affiliates | 3,277 |
| | 3,415 |
| | 3,501 |
| | 4,323 |
| | 3,029 |
|
Wholesale — affiliates | 800 |
| | 1,398 |
| | 552 |
| | 1,117 |
| | 496 |
|
Total | 86,478 |
| | 89,686 |
| | 87,858 |
| | 89,180 |
| | 84,705 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.38 |
| | 12.03 |
| | 12.16 |
| | 12.35 |
| | 12.00 |
|
Commercial | 9.62 |
| | 9.34 |
| | 9.46 |
| | 10.09 |
| | 9.62 |
|
Industrial | 5.62 |
| | 5.44 |
| | 5.48 |
| | 6.48 |
| | 6.03 |
|
Total retail | 9.39 |
| | 9.16 |
| | 9.22 |
| | 9.84 |
| | 9.39 |
|
Wholesale | 4.64 |
| | 4.51 |
| | 5.80 |
| | 6.93 |
| | 8.54 |
|
Total sales | 9.17 |
| | 8.91 |
| | 9.06 |
| | 9.66 |
| | 9.35 |
|
Residential Average Annual Kilowatt-Hour Use Per Customer | 12,028 |
| | 12,864 |
| | 12,582 |
| | 12,969 |
| | 12,293 |
|
Residential Average Annual Revenue Per Customer | $ | 1,489 |
| | $ | 1,557 |
| | $ | 1,529 |
| | $ | 1,605 |
| | $ | 1,475 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts) | 15,274 |
| | 15,274 |
| | 15,455 |
| | 17,593 |
| | 17,586 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 13,894 |
| | 14,527 |
| | 15,735 |
| | 16,308 |
| | 12,767 |
|
Summer | 16,002 |
| | 16,244 |
| | 16,104 |
| | 15,777 |
| | 15,228 |
|
Annual Load Factor (percent) | 61.1 |
| | 61.9 |
| | 61.9 |
| | 61.2 |
| | 63.5 |
|
Plant Availability (percent): | | | | | | | | | |
Fossil-steam | 85.0 |
| | 87.4 |
| | 85.6 |
| | 86.3 |
| | 87.1 |
|
Nuclear | 93.5 |
| | 95.6 |
| | 94.1 |
| | 90.8 |
| | 91.8 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Oil and gas | 28.6 |
| | 28.2 |
| | 28.3 |
| | 26.3 |
| | 29.6 |
|
Coal | 22.4 |
| | 26.4 |
| | 24.5 |
| | 30.9 |
| | 26.4 |
|
Nuclear | 17.8 |
| | 17.6 |
| | 17.6 |
| | 16.7 |
| | 17.7 |
|
Hydro | 1.0 |
| | 1.1 |
| | 1.6 |
| | 1.3 |
| | 2.0 |
|
Other | 0.3 |
| | — |
| | — |
| | — |
| | — |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 7.8 |
| | 6.7 |
| | 5.0 |
| | 3.8 |
| | 3.3 |
|
From affiliates | 22.1 |
| | 20.0 |
| | 23.0 |
| | 21.0 |
| | 21.0 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
SELECTED FINANCIAL AND OPERATING DATA 2011-2015 (continued)
Georgia Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 3,240 |
| | $ | 3,350 |
| | $ | 3,058 |
| | $ | 2,986 |
| | $ | 3,241 |
|
Commercial | 3,094 |
| | 3,271 |
| | 3,077 |
| | 2,965 |
| | 3,217 |
|
Industrial | 1,305 |
| | 1,525 |
| | 1,391 |
| | 1,322 |
| | 1,547 |
|
Other | 88 |
| | 94 |
| | 94 |
| | 89 |
| | 94 |
|
Total retail | 7,727 |
| | 8,240 |
| | 7,620 |
| | 7,362 |
| | 8,099 |
|
Wholesale — non-affiliates | 215 |
| | 335 |
| | 281 |
| | 281 |
| | 341 |
|
Wholesale — affiliates | 20 |
| | 42 |
| | 20 |
| | 20 |
| | 32 |
|
Total revenues from sales of electricity | 7,962 |
| | 8,617 |
| | 7,921 |
| | 7,663 |
| | 8,472 |
|
Other revenues | 364 |
| | 371 |
| | 353 |
| | 335 |
| | 328 |
|
Total | $ | 8,326 |
| | $ | 8,988 |
| | $ | 8,274 |
| | $ | 7,998 |
| | $ | 8,800 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 26,649 |
| | 27,132 |
| | 25,479 |
| | 25,742 |
| | 27,223 |
|
Commercial | 32,719 |
| | 32,426 |
| | 31,984 |
| | 32,270 |
| | 32,900 |
|
Industrial | 23,805 |
| | 23,549 |
| | 23,087 |
| | 23,089 |
| | 23,519 |
|
Other | 632 |
| | 633 |
| | 630 |
| | 641 |
| | 657 |
|
Total retail | 83,805 |
| | 83,740 |
| | 81,180 |
| | 81,742 |
| | 84,299 |
|
Wholesale — non-affiliates | 3,501 |
| | 4,323 |
| | 3,029 |
| | 2,934 |
| | 3,904 |
|
Wholesale — affiliates | 552 |
| | 1,117 |
| | 496 |
| | 600 |
| | 626 |
|
Total | 87,858 |
| | 89,180 |
| | 84,705 |
| | 85,276 |
| | 88,829 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 12.16 |
| | 12.35 |
| | 12.00 |
| | 11.60 |
| | 11.91 |
|
Commercial | 9.46 |
| | 10.09 |
| | 9.62 |
| | 9.19 |
| | 9.78 |
|
Industrial | 5.48 |
| | 6.48 |
| | 6.03 |
| | 5.73 |
| | 6.58 |
|
Total retail | 9.22 |
| | 9.84 |
| | 9.39 |
| | 9.01 |
| | 9.61 |
|
Wholesale | 5.80 |
| | 6.93 |
| | 8.54 |
| | 8.52 |
| | 8.23 |
|
Total sales | 9.06 |
| | 9.66 |
| | 9.35 |
| | 8.99 |
| | 9.54 |
|
Residential Average Annual Kilowatt-Hour Use Per Customer | 12,582 |
| | 12,969 |
| | 12,293 |
| | 12,509 |
| | 13,288 |
|
Residential Average Annual Revenue Per Customer | $ | 1,529 |
| | $ | 1,605 |
| | $ | 1,475 |
| | $ | 1,451 |
| | $ | 1,582 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts) | 15,455 |
| | 17,593 |
| | 17,586 |
| | 17,984 |
| | 16,588 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 15,735 |
| | 16,308 |
| | 12,767 |
| | 14,104 |
| | 14,800 |
|
Summer | 16,104 |
| | 15,777 |
| | 15,228 |
| | 16,440 |
| | 16,941 |
|
Annual Load Factor (percent) | 61.9 |
| | 61.2 |
| | 63.5 |
| | 59.1 |
| | 59.5 |
|
Plant Availability (percent)*: | | | | | | | | | |
Fossil-steam | 85.6 |
| | 86.3 |
| | 87.1 |
| | 90.3 |
| | 88.6 |
|
Nuclear | 94.1 |
| | 90.8 |
| | 91.8 |
| | 94.1 |
| | 92.2 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 24.5 |
| | 30.9 |
| | 26.4 |
| | 26.6 |
| | 44.4 |
|
Nuclear | 17.6 |
| | 16.7 |
| | 17.7 |
| | 18.3 |
| | 16.6 |
|
Hydro | 1.6 |
| | 1.3 |
| | 2.0 |
| | 0.7 |
| | 1.1 |
|
Oil and gas | 28.3 |
| | 26.3 |
| | 29.6 |
| | 22.0 |
| | 8.9 |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 5.0 |
| | 3.8 |
| | 3.3 |
| | 6.8 |
| | 6.1 |
|
From affiliates | 23.0 |
| | 21.0 |
| | 21.0 |
| | 25.6 |
| | 22.9 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
|
| |
* | Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
GULF POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Gulf Power Company 20152017 Annual Report
The management of Gulf Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2015.2017.
/s/ S. W. Connally, Jr.
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer
/s/ Xia LiuRobin B. Boren
Xia LiuRobin B. Boren
Vice President, and Chief Financial Officer, and Treasurer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of
Gulf Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Gulf Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014, and2016, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2015. 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-353 to II-391) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements based on our audits.
We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements (pages II-319 to II-357) present fairly, in all material respects, the financial position of Gulf Power Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
AFUDC | Allowance for funds used during construction |
Alabama Power | Alabama Power Company |
ARO | Asset retirement obligation |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
NOX | Nitrogen oxide |
OCI | Other comprehensive income |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company(excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreement |
PSC | Public Service Commission |
ROE | Return on equity |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
scrubber | Flue gas desulfurization system |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power Company, and Mississippi Power |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power Company 20152017 Annual Report
OVERVIEW
Business Activities
Gulf Power Company (the Company) operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service areaterritory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, fuel, and fuel.capital expenditures. The Company has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future. Through 2015, capacity revenues represented
On April 4, 2017, the majorityFlorida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among the Company and three intervenors with respect to the Company's request in 2016 to increase retail base rates. Among the terms of the Company's wholesale earnings.2017 Rate Case Settlement Agreement, the Company increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The Company had long-term sales contracts to cover 100% of its ownership share of Plant Scherer Unit 3 (205 MWs) and these capacity revenues represented 82% of total wholesale capacity revenues for 2015. Due to the expirationnet customer impact consisted of a $62.0 million increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale contract at the endrevenues of 2015 and future expiration dates of the remaining wholesale contracts for the unit,approximately $8 million through December 2019. In addition, the Company currently has contractscontinued its authorized retail ROE midpoint (10.25%) and range (9.25% to cover 34% of the unit for 2016 and 27% of the unit through 2019. Although the Company11.25%), is actively evaluating alternatives relating to this asset, including replacement wholesale contracts, the expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on the Company's earnings in 2016 and may continuedeemed to have a material negative impactmaximum equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. The Company also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in future years. In the event some portiona $32.5 million write-down of the Company's ownership of Plant Scherer Unit 3 is not subject(205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of the Company's investment in Plant Scherer Unit 3 in retail rates have been resolved as a replacement long-term wholesale contract,result of the proportionate amount2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit may be sold intothrough the Southern Company power pool or into the wholesale market.environmental cost recovery clause.
In 2013, the Florida PSC voted to approve the settlement agreement (2013The 2017 Rate Case Settlement Agreement) amongAgreement set forth a process for addressing the Company and allrevenue requirement effects of the intervenorsTax Reform Legislation through a prospective change to the Company's retail base rate case.rates. Under the terms of the 20132017 Rate Case Settlement Agreement, by March 1, 2018, the Company (1) increasedmust identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates approximately $35in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million annually effective January 2014 and subsequently increasedto the Company's base rates approximately $20and $15.6 million annuallyto the Company's environmental cost recovery rates effective January 2015; (2) continued its current authorizedbeginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail ROE midpoint (10.25%)portion of unprotected (not subject to normalization) deferred tax liabilities through the Company's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and range (9.25% – 11.25%); (3) may reduce depreciation expense andthe Company will record a regulatory asset thatliability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be included as an offsetrefunded to retail customers in 2019 through the otherCompany's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase the Company's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of removal regulatory liability in an aggregate amount upthese matters cannot be determined at this time.
On October 25, 2017, the Florida PSC approved the Company's 2018 annual cost recovery clause factors to $62.5 million between January 2014 and June 2017,provide for a net annual revenue increase of which $28.5 million had been recorded as of December 31, 2015; and (4) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first.$63 million. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case"Cost Recovery Clauses" herein for additional details of the 2013 Rate Case Settlement Agreement.
Key Performance Indicatorsinformation.
The Company continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. The Company's financial success is directly
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile of these surveys in measuring performance, which the Company achieved in 2015.performance.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The Company's 2015 Peak Season EFOR of 0.87% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance. The Company's performance for 2015 was better than the target for these transmission and distribution reliability measures.
The Company uses net income after dividends on preference stock as the primary measure of the Company's financial performance. See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Earnings
The Company's 20152017 net income after dividends on preference stock was $148$135 million, representing an $8a $4 million, or 5.7%3.1%, increase over the previous year. The increase was primarily due to an increase inhigher retail base revenues effective January 1, 2015, and lower depreciation, partially offset by a reduction in depreciation, both as authorized inwrite-down of $32.5 million ($20 million after tax) of the 2013Company's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement partially offsetand by higher operations and maintenance expenses as compared to the corresponding period in 2014.2016.
In 2016, the net income after dividends on preference stock was $131 million, representing a $17 million, or 11.5%, decrease over the previous year. The decrease was primarily due to lower wholesale revenues and higher depreciation, partially offset by higher retail revenues and lower operations and maintenance expenses as compared to the corresponding period in 2015.
RESULTS OF OPERATIONS
A condensed statement of income follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2017 | | 2017 | | 2016 |
| (in millions) |
Operating revenues | $ | 1,516 |
| | $ | 31 |
| | $ | 2 |
|
Fuel | 427 |
| | (5 | ) | | (13 | ) |
Purchased power | 155 |
| | 13 |
| | 7 |
|
Other operations and maintenance | 359 |
| | 23 |
| | (18 | ) |
Depreciation and amortization | 137 |
| | (35 | ) | | 31 |
|
Taxes other than income taxes | 116 |
| | (4 | ) | | 2 |
|
Loss on Plant Scherer Unit 3 | 33 |
| | 33 |
| | — |
|
Total operating expenses | 1,227 |
| | 25 |
| | 9 |
|
Operating income | 289 |
| | 6 |
| | (7 | ) |
Total other income and (expense) | (60 | ) | | (8 | ) | | (11 | ) |
Income taxes | 90 |
| | (1 | ) | | (1 | ) |
Net income | 139 |
| | (1 | ) | | (17 | ) |
Dividends on preference stock | 4 |
| | (5 | ) | | — |
|
Net income after dividends on preference stock | $ | 135 |
| | $ | 4 |
| | $ | (17 | ) |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
In 2014, the net income after dividends on preference stock was $140 million, representing a $16 million, or 12.7%, increase over the previous year. The increase was primarily due to higher retail revenues, partially offset by higher other operations and maintenance expenses as compared to the corresponding period in 2013.
RESULTS OF OPERATIONS
A condensed statement of income follows:
|
| | | | | | | | | | | |
| Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 |
| (in millions) |
Operating revenues | $ | 1,483 |
| | $ | (107 | ) | | $ | 150 |
|
Fuel | 445 |
| | (160 | ) | | 72 |
|
Purchased power | 135 |
| | 28 |
| | 22 |
|
Other operations and maintenance | 354 |
| | 13 |
| | 31 |
|
Depreciation and amortization | 141 |
| | (4 | ) | | (4 | ) |
Taxes other than income taxes | 118 |
| | 7 |
| | 13 |
|
Total operating expenses | 1,193 |
| | (116 | ) | | 134 |
|
Operating income | 290 |
| | 9 |
| | 16 |
|
Total other income and (expense) | (41 | ) | | 3 |
| | 9 |
|
Income taxes | 92 |
| | 4 |
| | 8 |
|
Net income | 157 |
| | 8 |
| | 17 |
|
Dividends on preference stock | 9 |
| | — |
| | 1 |
|
Net income after dividends on preference stock | $ | 148 |
| | $ | 8 |
| | $ | 16 |
|
Operating Revenues
Operating revenues for 20152017 were $1.48$1.52 billion, reflecting a decreasean increase of $107$31 million from 2014. The following table summarizes the significant changes in2016. Details of operating revenues for the past two years:were as follows:
| | | Amount | Amount |
| 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Retail — prior year | $ | 1,267 |
| | $ | 1,170 |
| $ | 1,281 |
| | $ | 1,249 |
|
Estimated change resulting from – | | | | | | |
Rates and pricing | 22 |
| | 47 |
| 40 |
| | 30 |
|
Sales growth | — |
| | 8 |
| 2 |
| | — |
|
Weather | 3 |
| | 10 |
| (11 | ) | | 1 |
|
Fuel and other cost recovery | (43 | ) | | 32 |
| (31 | ) | | 1 |
|
Retail — current year | 1,249 |
| | 1,267 |
| 1,281 |
| | 1,281 |
|
Wholesale revenues – | | | | | | |
Non-affiliates | 107 |
| | 129 |
| 57 |
| | 61 |
|
Affiliates | 58 |
| | 130 |
| 108 |
| | 75 |
|
Total wholesale revenues | 165 |
| | 259 |
| 165 |
| | 136 |
|
Other operating revenues | 69 |
| | 64 |
| 70 |
| | 68 |
|
Total operating revenues | $ | 1,483 |
| | $ | 1,590 |
| $ | 1,516 |
| | $ | 1,485 |
|
Percent change | (6.7 | )% | | 10.4 | % | 2.1 | % | | N/M |
|
N/M - Not meaningful
In 2015,2017, retail revenues decreased $18remained flat when compared to 2016 primarily due to an increase in retail base revenues effective with the first billing cycle in July 2017, offset by decreases in fuel and purchased power capacity clause revenues and the impact of milder weather. In 2016, retail revenues increased $32 million, or 1.4%2.6%, when compared to 20142015 primarily as a result of lower fuelan increase in the Company's environmental cost recovery clause revenues, partially offset by higher revenues associated with purchased power capacity costs and higher revenues resulting from an increase in retail base rates, as authorizeda decrease in the 2013 Rate Case Settlement Agreement, as well as an increase in the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
environmental and energy conservation cost recovery clause rates, both effective in January 2015. In 2014, retail revenues increased $97 million, or 8.3%, when compared to 2013 primarily as a result of higher fuel cost recovery revenues and higher revenues resulting from an increase in retail base rates effective January 2014, as authorized in the 2013 Rate Case Settlement Agreement.revenues. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather.
In 2015,2017, revenues associated with changes in rates and pricing included higher revenuesincreased primarily due to increasesan increase in retail base rates andeffective with the Company's environmental and energy conservation cost recovery clauses.first billing cycle in July 2017. In 2014,2016, revenues associated with changes in rates and pricing included higher revenuesincreased primarily due to an increase in retail base rates and revenues associated with higher rates under the Company's environmental cost recovery clause.clause as a result of additional rate base investment related to environmental compliance equipment placed in service at the end of 2015 as well as portions of the Company's ownership in Plant Scherer Unit 3 that were rededicated to retail service in 2016. Annually, the Company petitions the Florida PSC for recovery of projected environmental and energy conservation costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions include related expenses and a return on average net investment.
Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance.compliance, and a credit for certain wholesale revenues as a result of the 2017 Rate Case Settlement Agreement. Annually, the Company petitions the Florida PSC for recovery of projected fuel and purchased power costs, including any true-up amount from prior periods, and approved rates are implemented each January. The recovery provisions generally equal the related expenses and have no material effect on earnings.
See Note 1 to the financial statements under "Revenues" and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information regarding the Company's retail base rate case andcases, cost recovery clauses, including the Company's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.related rate changes.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Wholesale revenues from power sales to non-affiliated utilities were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Capacity and other | $ | 67 |
| | $ | 65 |
| | $ | 64 |
| $ | 25 |
| | $ | 30 |
| | $ | 67 |
|
Energy | 40 |
| | 64 |
| | 45 |
| 32 |
| | 31 |
| | 40 |
|
Total non-affiliated | $ | 107 |
| | $ | 129 |
| | $ | 109 |
| $ | 57 |
| | $ | 61 |
| | $ | 107 |
|
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. See FUTURE EARNINGS POTENTIAL – "General" for additional information regarding the expiration of long-term sales agreements for Plant Scherer Unit 3, which will materially impact future wholesale earnings.
In 2015,2017, wholesale revenues from sales to non-affiliates decreased $22$4 million, or 17.1%6.6%, as compared to the prior year primarily due to a 37.7%16.0% decrease in KWH salescapacity revenues resulting from lower sales under the expiration of a Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas market prices that led to increased self-generation from customer-owned units.agreement in 2016. In 2014,2016, wholesale revenues from sales to non-affiliates increased $20decreased $46 million, or 18.1%43.0%, as compared to the prior year primarily due to a 43.7% increase55.3% decrease in KWH sales as a result of lower-priced energy supply alternativescapacity revenues resulting from the Southern Company system's resources and fewer planned outages atexpiration of Plant Scherer Unit 3 partially offset by a 1.9% decreaselong-term sales agreements in the price of energy sold to non-affiliates due to the lower cost of fuel per KWH generated.December 2015 and May 2016.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold. In 2015,2017, wholesale revenues from sales to affiliates decreased $72increased $33 million, or 55.4%44.0%, as compared to the prior year primarily due to a 23.5% decrease39.6% increase in the price of energy soldKWH sales to affiliates due to the dispatch of the Company's lower power pool interchange rates resulting from lower natural gas market prices and a 42.0% decrease in KWH sales that resulted from the availability of lower-costcost generation alternatives.resources to serve system territorial load. In 2014,2016, wholesale revenues from sales to affiliates increased $30$17 million, or 30.7%29.3%, as compared to the prior year primarily due to a 24.5%46.1% increase in KWH sales to affiliates due to lower planned unit outages for the Company's generation resources and a 7.9% increase in the price of energy sold to affiliates due to higher marginal generation costs and a 5.0% increase in KWHmore sales as a result of an increase of the Company's generation dispatched to serve affiliated companies' higher weather-related energy demand primarily in the first and third quarters of 2014.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Other operating revenues increased $5 million, or 7.8%, in 2015 as compared to the prior year primarily due to a $2 million increase in franchise fees and a $2 million increase in revenues from other energy services. In 2014, other operating revenues increased $3 million, or 5.5%, as compared to the prior year primarily due to a $5 million increase in franchise fees due to increased retail revenues, partially offset by a $2 million decrease in revenues from other energy services. Franchise fees have no impact on net income. Revenues from other energy services did not have a material effect on net income since they were generally offset by associated expenses.during peak load hours.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 20152017 and the percent change from the prior year were as follows:
| | | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2015 | | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) |
| | | | | | | | | (in millions) |
| | | | | | | | |
Residential | 5,365 |
| | — | % | | 5.4 | % | | (1.0 | )% | | 1.3 | % | 5,229 |
| | (2.4 | )% | | (0.1 | )% | | 1.3 | % | | (0.2 | )% |
Commercial | 3,898 |
| | 1.6 |
| | 0.7 |
| | 0.3 |
| | 0.1 |
| 3,814 |
| | (1.4 | ) | | (0.7 | ) | | — |
| | (1.5 | ) |
Industrial | 1,798 |
| | (2.8 | ) | | 8.8 |
| | (2.8 | ) | | 8.8 |
| 1,740 |
| | (5.0 | ) | | 1.8 |
| | (5.0 | ) | | 1.8 |
|
Other | 25 |
| | (0.1 | ) | | 20.5 |
| | (0.1 | ) | | 20.5 |
| 26 |
| | 4.5 |
| | (0.8 | ) | | 4.5 |
| | (0.8 | ) |
Total retail | 11,086 |
| | 0.1 |
| | 4.3 |
| | (0.8 | )% | | 2.1 | % | 10,809 |
| | (2.5 | ) | | — |
| | (0.2 | )% | | (0.3 | )% |
Wholesale | | | | | | | | | | | | | | | | | | |
Non-affiliates | 1,040 |
| | (37.7 | ) | | 43.7 |
| | | | | 749 |
| | (0.1 | ) | | (27.8 | ) | | | | |
Affiliates | 1,906 |
| | (42.0 | ) | | 5.0 |
| | | | | 3,887 |
| | 39.6 |
| | 46.1 |
| | | | |
Total wholesale | 2,946 |
| | (40.5 | ) | | 15.5 |
| | | | | 4,636 |
| | 31.2 |
| | 20.0 |
| | | | |
Total energy sales | 14,032 |
| | (12.5 | )% | | 7.5 | % | | | | | 15,445 |
| | 5.7 | % | | 4.2 | % | | | | |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers.
Residential Retail energy sales decreased 2.5% in 2017 compared to the prior year primarily due to milder weather in the first half of the year, partially offset by customer growth. Weather-adjusted residential KWH sales increased minimally
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
primarily due to customer growth. Weather-adjusted commercial KWH sales remained flat as a result of lower customer usage primarily resulting from efficiency improvements in 2015appliances and lighting, offset by customer growth. Industrial KWH sales decreased in 2017 compared to 20142016 primarily due to changes in customers' operations and energy efficiency improvements.
Residential and commercial KWH sales decreased in 2016 compared to 2015 due to declining use per customer primarily resulting from energy efficiency improvements, partially offset by customer growth and warmer weather induring the second and third quarters of 2015, mostly offset by a decline in use per customer. Residential KWH sales increased in 2014 compared to 2013 primarily due to colder weather in the first quarter of 2014 and customer growth.
Commercial KWH sales increased in 2015 compared to 2014 due to customer growth and warmer weather in the second and third quarters of 2015, partially offset by a decline in use per customer. Commercial KWH sales increased in 2014 compared to 2013 primarily due to colder weather in the first quarter of 2014 and customer growth, partially offset by a decline in weather-adjusted use per customer.
Industrial KWH sales decreased in 2015 compared to 2014 primarily due to increased customer co-generation as a result of lower natural gas prices, partially offset by increases due to changes in customers' operations.quarter. Industrial KWH sales increased in 20142016 compared to 20132015 primarily due to decreased customer co-generation, andpartially offset by changes in customers' operations.
See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the single largest expenseexpenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Details of the Company's generation and purchased power were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Total generation (millions of KWHs) | 8,629 |
| | 11,109 |
| | 9,216 |
| |
Total purchased power (millions of KWHs) | 5,976 |
| | 5,547 |
| | 6,298 |
| |
Total generation (in millions of KWHs) | | 9,310 |
| | 8,259 |
| | 8,629 |
|
Total purchased power (in millions of KWHs) | | 5,991 |
| | 6,973 |
| | 5,976 |
|
Sources of generation (percent) – | | | | | | | | | | |
Coal | 57 |
| | 67 |
| | 61 |
| 54 |
| | 57 |
| | 57 |
|
Gas | 43 |
| | 33 |
| | 39 |
| 46 |
| | 43 |
| | 43 |
|
Cost of fuel, generated (cents per net KWH) – | | | | | | |
Cost of fuel, generated (in cents per net KWH) – | | | | | | |
Coal(a) | 3.88 |
| | 4.03 |
| | 4.12 |
| 3.14 |
| | 3.68 |
| | 3.88 |
|
Gas | 4.22 |
| | 3.93 |
| | 3.95 |
| 3.55 |
| | 4.17 |
| | 4.22 |
|
Average cost of fuel, generated (cents per net KWH)(a) | 4.03 |
| | 3.99 |
| | 4.05 |
| |
Average cost of purchased power (cents per net KWH)(b) | 3.89 |
| | 4.83 |
| | 3.88 |
| |
Average cost of fuel, generated (in cents per net KWH) | | 3.32 |
| | 3.89 |
| | 4.03 |
|
Average cost of purchased power (in cents per net KWH)(*) | | 4.55 |
| | 3.63 |
| | 3.89 |
|
|
| |
(a) | 2013 cost of coal includes the effect of a payment received pursuant to the resolution of a coal contract dispute. |
(b) | Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider. |
(*)Average cost of purchased power includes fuel purchased by the Company for tolling agreements where power is generated by the provider.In 2015,2017, total fuel and purchased power expenses were $580$582 million, an increase of $8 million, or 1.4%, from the prior year costs. The increase was primarily the result of a $6 million net increase due to a higher volume of KWHs generated and purchased and a $2 million net increase due to a higher average cost of fuel and purchased power.
In 2016, total fuel and purchased power expenses were $574 million, a decrease of $132$6 million, or 18.5%1.0%, from the prior year costs. The decrease was primarily the result of a $79 million decrease due to a lower volume of KWHs generated and purchased due to the availability of lower-cost generation alternatives and a $53$30 million decrease due to a lower average cost of fuel and purchased power.
In 2014, total fuel and purchased power, expenses were $712largely offset by a $24 million an increase of $94 million, or 15.2%, from the prior year costs. Total fuel and purchased power expenses for 2013 includeddue to a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding the payment, the higher volume of KWHs generated and purchased increased expenses $55 million primarily due to increased Company owned generation dispatched to serve higher Southern Company system demand as a result of colder weather in the first quarter and warmer weather in the third quarter 2014. The increased expenses also included an $18 million increase due to a higher average cost of fuel and purchased power.purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through the Company's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" for additional information.
Fuel
Fuel expense was $445$427 million in 2015,2017, a decrease of $160$5 million, or 26.4%1.2%, from the prior year costs. The decrease was primarily due to a 22.3% lower volume of KWHs generated due to the availability of lower-cost generation alternatives, partially offset by a 1.0% increase14.7% decrease in the average cost of fuel due to higher natural gas prices per KWH generated. In 2014, fuel expense was $605 million, an increase of $72 million, or 13.5%, from the prior year costs. The increase was primarily due to a 20.5% higher volume of KWHs generated to serve higher Southern Company system loads due to colder weather in the first quarter 2014 and warmer weather in the third quarter 2014. The fuel expense for 2013 included a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding the payment, the average cost of fuel per KWH generated decreased 6.8%.
Purchased Power – Non-Affiliates
Purchased powerdue to lower coal and natural gas prices, partially offset by a 12.7% higher volume of KWHs generated due to the dispatch of the Company's lower cost generation resources to serve system territorial load. In 2016, fuel expense from non-affiliates was $100$432 million, in 2015, an increasea decrease of $18$13 million, or 22.0%2.9%, from the prior year.year costs. The increasedecrease was primarily due to a $26 million increase in capacity costs associated with a scheduled price increase for an existing PPA, partially offset by the expiration of another PPA, an 11.9%3.5% decrease in the average cost of fuel per KWH purchasedgenerated due to lower marketcoal and natural gas prices for fuel, and a 7.8% decrease in the4.3% lower volume of KWHs purchasedgenerated due to the availability of lower-cost generation alternatives. In 2014, purchased power expense from non-affiliates was $82 million in 2014, an increase of $30 million, or 56.3%, from the prior year. The increase was due to a 37.3% increase in the average cost per KWH purchased, which included a $28 million increase in capacity costs associated with a scheduled price increase for an existing PPA, partially offset by the expiration of another PPA. This increase was partially offset by a 16.3% decrease in the volume of KWHs purchased due to colder regional weather conditions in the first quarter 2014 which limited the availability of marketfrom lower-cost gas-fired PPA resources.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
Purchased Power
Purchased power expense was $155 million in 2017, an increase of $13 million, or 9.2%, from the prior year. The increase was primarily due to a 25.3% increase in the average cost per KWH purchased, partially offset by a 14.1% decrease in the volume of KWHs purchased. In 2016, purchased power expense was $142 million, an increase of $7 million, or 5.2%, from the prior year. The increase was primarily due to a 16.7% increase in the volume of KWHs purchased, partially offset by a 6.7% decrease in the average cost per KWH purchased resulting from lower energy costs from gas-fired resources.
Energy purchases from non-affiliates and affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
Purchased power expense from affiliates was $35 million in 2015, an increase of $10 million, or 40.0%, from the prior year. The increase was primarily due to a 108.9% increase in the volume of KWHs purchased primarily due to the availability of lower-cost generation alternatives available from the power pool, partially offset by a 34.2% decrease in the average cost per KWH purchased due to lower power pool interchange rates. In 2014, purchased power expense from affiliates was $25 million, a decrease of $8 million, or 23.1%, from the prior year. The decrease was primarily due to a 43.3% decrease in the average cost per KWH purchased, which included a $14 million reduction in capacity costs primarily associated with the expiration of an existing PPA. This decrease was partially offset by a 33.2% increase in the volume of KWHs purchased primarily due to higher planned outages for the Company's generating units in the fourth quarter 2014.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These Affiliate purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
In 2015,2017, other operations and maintenance expenses increased $13$23 million, or 3.8%6.8%, compared to the prior year primarily due to increases of $7 million in environmental compliance expenses, $6 million in employee compensation and benefits including pension costs,rate case expense amortization of $3 million of expenses previously incurred in retail base rate cases as authorized inrelated to the 20132017 Rate Case Settlement Agreement, $6 million in routine and $2planned maintenance at generation facilities, and $3 million in energy service contracts.services expenses. In 2014,2016, other operations and maintenance expenses increased $31decreased $18 million, or 10.1%5.1%, compared to the prior year primarily due to increasesdecreases of $7 million in marketing incentive programs and $6 million in routine and planned maintenance expenses at generation transmissionfacilities. Also contributing to the decrease was $4 million in rate case expense amortization recorded in 2015 and distribution facilities.a $3 million reduction in employee compensation and benefits expenses including pension costs.
Expenses from energy services and marketing incentive programs did not have a significant impact on earnings since they were generally offset by associated revenues. Rate case expenses were amortized as authorized in the 2017 Rate Case Settlement Agreement and a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement). See Note 3 to the financial statements under "Retail Regulatory Matters – Base Rate Cases" and " – Cost Recovery Clauses" and Note 2 to the financial statements for additional information related to rate case expenses and environmental compliance costs and pension costs, respectively.
Depreciation and Amortization
Depreciation and amortization decreased $4$35 million, or 2.8%20.3%, in 20152017 compared to the prior year. AsThe decrease was primarily due to the reduction in depreciation of $34.0 million recorded in 2017, as authorized in the 2013 Rate Case Settlement Agreement. In 2016, depreciation and amortization increased $31 million, or 22.0%, compared to the prior year. The increase was primarily due to a reduction in depreciation of $20.1 million recorded in 2015, as authorized in the 2013 Rate Case Settlement Agreement, the Company recorded an $11.7 million additional reduction in depreciation in 2015 as compared to 2014. This decrease was partially offset byand an increase of $8$9 million primarily attributable to property additions at transmission and distribution facilities. In 2014, depreciation and amortization decreased $4 million, or 2.7%, compared to the prior year. As authorized in the 2013 Rate Case Settlement Agreement, the Company recorded an $8.4 million reduction in depreciation in 2014. This decrease was partially offset by increases of $4 million primarily attributable to property additions at generation, transmission, and distribution facilities.utility plant. See Note 3 to the financial statements under "Retail Regulatory Matters – Retail Base Rate Case"Cases" for additional information.
TaxesTotal Other Than Income Taxesand (Expense)
TaxesIn 2017, total other than income taxes increased $7and (expense) decreased $8 million, or 6.3%, in 2015 compared to the prior year primarily due to increases of $3 million in property taxes, $2 million in franchise fees and $2 million in gross receipts taxes. In 2014, taxes other than income taxes increased $13 million, or 13.0%15.4%, compared to the prior year primarily due to increases of $4a $5 million increase in franchise feesdonations and $4 million in gross receipts taxes as well as a $3 million increase in property taxes. Gross receipts taxes and franchise fees are based on billed revenues and have no impact on net income. These taxes are collected from customers and remitted to governmental agencies.
Interest Expense, Net of Amounts Capitalized
Interestinterest expense, net of amounts capitalized decreased $4 million, or 7.5%,capitalized. The increase in 2015 compared to the prior yearinterest expense was primarily due to $6 million in deferred returns on transmission projects in 2016, which reducereduced interest expense and arewere recorded as a regulatory asset, as authorized in the 2013 Rate Case Settlement Agreement. ThisIn 2016, total other income and (expense) decreased $11 million, or 26.8%, primarily due to a decrease wasof $13 million in AFUDC equity related to environmental control projects at generating facilities and transmission projects placed in service in 2015, partially offset by a $2 million increasedecrease in interest expense related to long-term debt resulting from the issuance of senior notes in 2014. In 2014, interest expense, net of amounts capitalized, primarily due to the redemption of debt. See Note 1 to the financial statements under "Allowance for Funds Used During Construction" for additional information.
Dividends on Preference Stock
Dividends on preference stock decreased $3$5 million, or 5.0%55.6%, in 2017 compared to the prior year primarily due to an increasethe redemption of all preference stock in capitalization of AFUDC debt related to the construction of environmental control projects and lower interest rates on pollution control bonds, offset by increases in long-term debt resulting from the issuance of additional senior notes in 2014.
MANAGEMENT'S DISCUSSIONJune 2017. See FINANCIAL CONDITION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Income Taxes
Income taxes increased $4 million, or 4.5%, in 2015 compared to the prior year primarily due to higher pre-tax earnings. In 2014, income taxes increased $8 million, or 10.5%, compared to the prior year primarily due to higher pre-tax earnings. See Note 5 to the financial statements under "Effective Tax Rate"LIQUIDITY – "Financing Activities" herein for additional information.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service areaterritory located in northwest Florida and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Florida PSC under cost-based regulatory principles. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Electric Utility Regulation" herein and Note 3 to the financial statements under "Retail Regulatory Matters" for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the Company's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs.costs and limited projected demand growth over the next several years. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior, both of which could contribute to a net reduction in customer usage. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory, and the successful remarketing of wholesale capacity as current contracts expire.territory. Demand for electricity is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements for additional information.
Environmental Matters
The Company's wholesale business consistsoperations are regulated by state and federal environmental agencies through a variety of two typeslaws and regulations governing air, water, land, and protection of agreements. The first type, referred to as requirements service, provides that the Company serves the customer's capacity and energy requirements from Companyother natural resources. The second type, referredCompany maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where awell as related upgrades to the transmission system. A major portion of that unit is reserved forthese compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the customer. These agreements are associated withenvironmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the Company's ownershipavailability and cost of Plant Scherer Unit 3any deployed control technology, and consistthe outcome of both capacitypending and/or future legal challenges.
New or revised environmental laws and energy sales. Through 2015, capacity revenues represented the majorityregulations could affect many areas of the Company's wholesale earnings.operations. The Company had long-term sales contracts to cover 100%impact of its ownership share of Plant Scherer Unit 3 and these capacity revenues represented 82% of total wholesale capacity revenues for 2015. Due to the expiration of a wholesale contractany such changes cannot be determined at the end of 2015 and future expiration dates of the remaining wholesale contracts for the unit, the Company currently has contracts to cover 34% of the unit for 2016 and 27% of the unit through 2019. Although the Company is actively evaluating alternatives relating to this asset, including replacement wholesale contracts, the expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on the Company's earnings in 2016 and may continue to have a material negative impact in future years. In the event some portion of the Company's ownership of Plant Scherer Unit 3 is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the Southern Company power pool or into the wholesale market.
time. Environmental Matters
Compliancecompliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts.long-term wholesale agreements. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. The Company's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatory or legislative changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higherincreased costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity, as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See "Other Matters" herein and Note 3 to the financial statements under "Environmental Matters" and "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" for additional information, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.
Environmental Statutes and Regulations
General
The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015,2017, the Company hadhas invested approximately $1.9$2.0 billion in environmental capital retrofit projects to comply with theseenvironmental requirements, with annual totals of approximately $116 million, $227 million, and $143 million for 2015, 2014, and 2013, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $117 million from 2016 through 2018, with annual totals of approximately $30 million, $43$28 million, and $44$116 million for 2017, 2016, 2017, and 2018,2015, respectively. These estimated expenditures do not include any potential capital expenditures that may arise fromAlthough the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" for additional information. The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, upgrades to the transmission system, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity.
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.
In 2012, the EPA finalized the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions to April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each Company unit. On June 29, 2015, the U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units. On December 15, 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliancetiming, requirements, and deadlines.estimated costs could change as environmental laws and regulations
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Gulf Power Company 20152017 Annual Report
are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $279 million from 2018 through 2022, with annual totals of approximately $65 million, $57 million, $83 million, $58 million, and $16 million for 2018, 2019, 2020, 2021, and 2022, respectively. These estimates do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Environmental Laws and Regulations
Air Quality
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozonehas set National Ambient Air Quality StandardStandards (NAAQS). for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2008, the EPA adopted a revised eight-hour ozone NAAQS, and published its final area designations in 2012. All areas within the Company's service territory have achieved attainment of the 2008 standard. On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October 2017.
The EPA regulates fine particulate matter concentrations on an annual and 24-hour average basis. All areas within the Company's service territory have achieved attainment with the 1997 and 2006 particulate matter NAAQS. In 2012, the EPA issued a final rule that increases the stringency of the annual fine particulate matter standard. The EPA promulgated finalplans to complete designations for the 2012 annual standard in December 2014, andthis rule by no new nonattainment areas were designated within the Company's service territory. The EPA has, however, deferred designation decisions for certain areas in Florida.
Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010.later than April 30, 2018. No areas within the Company's service territory have been or are anticipated to be designated as nonattainment under this rule. However,the 2015 ozone NAAQS. In 2010, the EPA has finalized a data requirements rule to support additional designation decisionsrevised the NAAQS for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the future, which could result in nonattainment designations for areas within the Company's service territory. Implementationvicinity of the revisedCompany-owned SO2 standard could require additional reductions insources have been designated nonattainment under the 2010 one-hour SO2 emissionsNAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance and operational costs.costs could result.
The Company's service territory is subject toIn 2011, the requirements ofEPA finalized the Cross StateCross-State Air Pollution Rule (CSAPR). and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that limitsaddresses the impacts of the interstate transport of SO2 and nitrogen oxideNOX emissions from fossil fuel-fired power plants located in 28upwind states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,the eastern half of the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Florida and Georgia, but rejected all other pending challengeson air quality in downwind states. The Company has fossil fuel-fired generation subject to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,these requirements. In October 2016, the EPA published a proposed revision tofinal rule that revised the CSAPR that would revise existing ozone-seasonseasonal NOX program, which completely removed Florida from all CSAPR programs, left the Georgia seasonal NOX budget unchanged, and established more stringent NOX emissions budgets for nitrogen oxide in Mississippi and would remove Florida fromMississippi. The outcome of ongoing CSAPR litigation could have an impact on the State of Mississippi's allowance allocations under the CSAPR seasonal NOXprogram. The EPA proposes to finalize this rulemaking by summer 2016.Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
The EPA finalized regional haze regulations in 2005 with aand 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, (primarilyincluding national parks and wilderness areas)areas. States must submit a revised state implementation plan (SIP) to the EPA by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieveJuly 31, 2021, demonstrating reasonable progress toward the naturaltowards achieving visibility conditions goal by 2018 and for each 10-year period thereafter.improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Florida, Georgia, and Mississippi) to revise or remove the provisions of their State Implementation Plans (SIPs) relating to the regulation ofSIPs regulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM) by no later than November 22, 2016.
. The Company has developedstate excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the currentif removed, could affect unit availability and proposed environmental requirements discussed above. As part of this strategy, the Company has developed a compliance planresult in increased operations and maintenance costs for the MATS rule which includes reliance on existing emission control technologies,Company. The EPA has not yet responded to the use of existing or additional natural gas capability, and unit retirements. Additionally, certain transmission system upgradesSIP revisions proposed by states where the Company's generating units are required. The impacts of the eight-hour ozone, fine particulate matter and SO2 NAAQS, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through PPAs.located.
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existingIn 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014.order to minimize their effects on fish and other aquatic life. The effectregulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this final rule will depend on the resultsoutcome of additionalthese plant-specific studies and implementation of the rule by regulatorsany additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
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Gulf Power Company 20152017 Annual Report
factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.
On November 3,In 2015, the EPA published a finalfinalized the steam electric effluent limitations guidelines (ELG) rule which imposes stringent technology-based requirementsthat set national standards for certain wastestreamswastewater discharges from steam electric power plants.generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected unitsmay require extensive modifications to existing ash and may requirewastewater management systems or the installation and operation of multiple technologies sufficientnew ash and wastewater management systems. Compliance with the ELG rule is expected to ensure compliance with applicable new numeric wastewater compliance limits.require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance deadlines betweenapplicability dates range from November 1, 2018 andto December 31, 2023 will be establishedwith state environmental agencies incorporating specific applicability dates in permitsthe NPDES permitting process based on information provided for each applicable wastestream.waste stream. The ultimate impact of these requirements will depend on pendingEPA has committed to a new rulemaking that could potentially revise the limitations and any future legal challenges, complianceapplicability dates and implementation of the final rule and cannot be determined atELG rule. The EPA expects to finalize this time.rulemaking in 2020.
On June 29,In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule revisingthat revised the regulatory definition of waters of the U.S.United States (WOTUS) for all Clean Water Act (CWA)CWA programs. The final rule significantly expandsexpanded the scope of federal jurisdiction under the CWAover waterbodies (such as rivers, streams, and could have significant impacts on economic development projectscanals), which could affect customer demand growth. In addition, this rule could significantly increaseimpact new generation projects and permitting and regulatoryreporting requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines.projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule became effective August 28, 2015, but on October 9, 2015,has been stayed by the U.S. Court of Appeals for the Sixth Circuit issued an order stayingsince late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the final rule. The ultimate impact of the final2015 WOTUS rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.to 2020.
In addition, numeric nutrient water quality standards promulgated by the State of Florida to limit the amount of nitrogen and phosphorous allowed in state waters are in effect for the State's streams and estuaries. The impact of these standards will depend on further regulatory action in connection with their site-specific implementation through the State of Florida's National Pollutant Discharge Elimination SystemNPDES permitting program and Total Maximum Daily Load restoration program and cannot be determined at this time.
These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs.
Coal Combustion Residuals
The Company currently manages CCR at onsite storage units consisting of landfills and surface impoundments (CCR Units) at three electric generating plants in Florida and is a co-owner of units at generating plants located in Mississippi and Georgia operated by Mississippi Power and Georgia Power, respectively. In addition to on-site storage, the Company sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the States of Florida, Georgia, and Mississippi each have their own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.
On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulatesfinalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Unitslandfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule does not automatically require closurerequires CCR units to be evaluated against a set of CCR Units but includesperformance criteria and potentially closed if minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansionsare not met. Closure of existing CCR units could require installation of equipment and active landfills. Failureinfrastructure to meetmanage CCR in accordance with the minimum criteria canrule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in the required closure of a CCR Unit. Although the EPA does not require individual stateschanges to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. deadlines and corrective action requirements.
The EPA's final rule continuesreconsideration of the CCR Rule is due in part to excludea legislative development that impacts the beneficial usepotential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR from regulation.Rule.
Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, and the closure of an ash pond at Plant Scholz, the Company recorded AROs related to thefor each CCR Rule.unit in 2015. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.cost estimates as necessary. The Company is currently completing an analysisestimated costs associated with closure of the plan of closure for all ash ponds includingat Plant Scholz and Plant Smith for 2018 have been approved for recovery through the timing of closure and relatedenvironmental cost recovery through regulated rates subject to Florida PSC approval. Based on the results of that analysis, the Company may accelerate the timing of some ash pond closures which could increase its ARO liabilities from the amounts presently recorded. The ultimate impact of the CCR Rule cannot be determined at this timeclause. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and will depend on the Company's ongoing review of the CCR Rule, the results of initialContractual Obligations" herein and ongoing minimum criteria assessments, and the outcome of legal challenges. The Company's results of operations, cash flows, and
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Gulf Power Company 2015 Annual Report
financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2015.2017.
Environmental Remediation
The Company must comply with other environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the estimated costs to clean up known impacted sites.affected sites in its financial statements. Included in this amount are costs associated with remediation of the Company's substation sites. These projects have been approved by the Florida PSC for recovery through the environmental cost recovery clause; therefore, these liabilities have no impact to the Company's net income. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Global Climate Issues
On October 23,In 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governingrules limiting CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishesfossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goalsperformance standards for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. Atunits (known as the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adoptClean Power Plan or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. OnCPP). In February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stayCPP, which will remain in effect through the resolution of the litigation whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit orchallenging the legality of the CPP and any review by the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the Company's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, including legal challenges filed byproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the traditional operating companies; individual state implementation of the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countries and cannot be determined at this time.countries.
The EPA's greenhouse gasGHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2014 greenhouse gas2016 GHG emissions were approximately 108 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2015 greenhouse gas2017 GHG emissions on the same basis is approximately 7 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
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Gulf Power Company 2017 Annual Report
Retail Regulatory Matters
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Retail Base Rate CaseCases
In 2013, the Florida PSC voted to approve the 2013 Rate Case Settlement Agreement among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its currentFlorida PSC authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first.
The 2013 Rate Case Settlement Agreement also provides that the Company mayto reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million betweenfrom January 2014 andthrough June 2017. In any given month, such depreciation expense reduction maywas not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's next base rate case or next depreciationFor 2014 and dismantlement study proceeding, whichever comes first. For 2015, and 2014, the Company recognized reductions in depreciation expense of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In 2017, the Company recognized the remaining $34.0 million reduction in depreciation.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among the Company and $8.4three intervenors with respect to the Company's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, the Company increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million respectively.increase in annual base revenues, less an annual purchased power capacity cost recovery clause credit for certain wholesale revenues of approximately $8 million through December 2019. In addition, the Company continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have a maximum equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. The Company also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of the Company's ownership of Plant Scherer Unit 3, which was recorded in the first quarter 2017. The remaining issues related to the inclusion of the Company's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to the Company's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, the Company must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed the 2018 Tax Reform Settlement Agreement with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to the Company's base rates and $15.6 million to the Company's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through the Company's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and the Company will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through the Company's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase the Company's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Cost Recovery Clauses
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to the Company's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On November 2, 2015,October 25, 2017, the Florida PSC approved the Company's 2016 annual cost recovery clause ratesrate request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery clauses.factors for 2018. The net effect of the approved changes is an expected $49a $63 million decreaseincrease in annual revenue for 2016. The decreased revenues will not have a significant impact on net income since mosteffective in January 2018, the majority of the revenueswhich will be offset by lower expenses.related expense increases.
Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment. See Note 1 to the financial statements under "Revenues" for additional information.
Renewables
On April 16, 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these solar agreements are expected to begin by early 2017. On May 5, 2015, the Florida PSC approved an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements began in January 2016, are for energy only, and will be recovered through the Company's fuel cost recovery mechanism.Income Tax Matters
Bonus DepreciationFederal Tax Reform Legislation
On December 18, 2015,22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Act.
In addition, under the Tax Reform Legislation, net operating losses (NOLs) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in a $25 million decrease in regulatory assets and a $456 million increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the Florida PSC and the FERC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the Company's rate filing to reflect the impacts of the Tax Reform Legislation.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus depreciation was extended for qualified propertyDepreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service overafter September 27, 2017 remain eligible for bonus depreciation under the next five years.PATH Act. The PATH Act allowsallowed for 50% bonus depreciation for 2015 2016, and 2017;through 2017, 40% bonus depreciation for 2018;2018, and 30% bonus depreciation for 2019 and for certain long-lived assets placed in service in 2020. The extensionBased on provisional estimates, approximately $20 million of 50% bonus depreciationpositive cash flows is expected to result from bonus depreciation for the 2017 tax year and approximately $10 million for the 2018 tax year. Should Southern Company have a NOL in approximately $105 million2018, all of these cash flows may not be fully realized in 2018. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 in March 2016. In August 2016, the Florida PSC approved the Company's request to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
positive cash flows for the 2015 tax year and the estimated cash flow benefit of bonus depreciation related to the PATH Act is expected to be approximately $27 million for the 2016 tax year.
Other Matters
On February 6, 2015, the Company announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016, as a result of the cost to comply with environmental regulations imposed by the EPA. In connection with this retirement, the Company reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. The net book value of these units at December 31, 2015 was approximately $62 million. Subsequent to December 31, 2015, the Company filed a petition with the Florida PSC requesting permission to create a regulatory asset forreclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining inventorymaterials and supplies associated with these units as of the retirement date.date, totaling approximately $63 million, to a regulatory asset. The retirement of these units is not expected to have a material impact onCompany began amortizing the Company's financial statements as the Company expects to recover these amounts through its rates; however, the ultimate outcome depends on future rate proceedingsinvestment balances over 15 years effective January 1, 2018 in accordance with the Florida PSC and cannot be determined at this time.2017 Rate Case Settlement Agreement.
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Florida PSC. The Florida PSC sets the rates the Company is permitted to charge customers based on allowable costs. The Company is also subject to cost-based regulation by the FERC with respect to wholesale transmission rates. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the Company's facilities that are subject to the CCR Rule and to the closure of an ash pond at Plant Scholz. In addition, the Company has retirement obligations related to combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
As a result of the final CCR Rule discussed above, the Company recorded newThe cost estimates for AROs for facilities that are subjectrelated to the disposal of CCR Rule. The cost estimates are based on information using various assumptions related to closure in place and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure.closure for those facilities impacted by the CCR Rule. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ForBeginning in 2016, the Company has adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense will decreasedecreased by approximately $4 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $1$2 million or less change in total annual benefit expense and a $19$25 million or less change in projected obligations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers revises(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. The Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606. The ultimate impact of the new standard has606 did not yet been determined.result in a cumulative-effect adjustment.
Leases
On April 7, 2015,In February 2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance CostsLeases (Topic 842) (ASU 2015-03)2016-02). ASU 2015-032016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015. As permitted,2018 and the Company elected to earlywill adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. new standard effective January 1, 2019.
The new guidance resulted inCompany is currently implementing an adjustment to the presentation of debt issuance costs as an offset toinformation technology system along with the related debt balances in long-term debt totaling $8 million aschanges to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of December 31, 2014. These debt issuance costs were previously presented within other deferredits leases. In terms of rental charges and assets. Other thanduration of contracts, the reclassification,most significant leases relate to a PPA, cellular towers, and barges where the Company is the lessee and to outdoor lighting and power distribution equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2015-03 did not2016-02 is expected to have ana significant impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 to the financial statements for disclosures impacted by ASU 2015-03.Company's balance sheet.
Other
On May 1, 2015,March 10, 2017, the FASB issued ASU No. 2015-07,2017-07, Fair Value MeasurementCompensation – Retirement Benefits (Topic 820)715): Disclosures for Investments in Certain Entities That CalculateImproving the Presentation of Net Asset Value per Share (or Its Equivalent)Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2015-07),2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for fiscal yearsperiods beginning after December 15, 2015. As permitted,2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments inadopted ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance2017-07 effective January 1, 2018 with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no material impact on the results of operations, cash flows, orits financial condition of the Company. See Note 2 to the financial statements for disclosures impacted by ASU 2015-07.statements.
On November 20, 2015,August 28, 2017, the FASB issued ASU No. 2015-17,2017-12, Income TaxesDerivatives and Hedging (Topic 740)815): Balance Sheet Classification of Deferred Taxes Targeted Improvements to Accounting for Hedging Activities( (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2015-17), which2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies the presentation of deferred income taxes.hedge effectiveness assessment requirements. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and2017-12 is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the2018, with early adoption permitted. The Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption ofadopted ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an2017-12 effective January 1, 2018 with no material impact on the results of operations, cash flows, orits financial condition of the Company. See Note 5 to the financial statements for disclosures impacted by ASU 2015-17.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2015.2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing facilities, to comply with environmental regulations including adding environmental modifications to existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 20162018 through 2018,2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Projected capital expenditures in that period are primarily to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities. The Company plans to finance future cash needs in
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
excess of its operating cash flows primarily through debt and equityexternal security issuances, in the capital markets, by accessing borrowings from financial institutions, and through equity contributions from Southern Company.Company, and borrowings from financial institutions. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's investments in the qualified pension plan decreasedincreased in value as of December 31, 20152017 as compared to December 31, 2014.2016. No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated during 2016.2018. See Note 2 to the financial statements under "Pension Plans" for additional information.
Net cash provided from operating activities totaled $460$356 million in 2015, an increase2017, a decrease of $116$23 million from 2014,2016, primarily due to increasesdecreases in cash flows related to clause recovery and bonus depreciation. This increase was partially offset by decreases related to the timing of fossil fuel stock purchases and vendor payments.clause recovery, partially offset by increases related to voluntary contributions to the qualified pension plan in 2016. Net cash provided from operating activities totaled $344$379 million in 2014, an increase2016, a decrease of $13$81 million from 2013,2015, primarily due to increasesdecreases in cash flows related to clause recovery partially offset by decreases in cash flows associated withand a voluntary contributionscontribution to the qualified pension plan.plan, partially offset by the timing of fossil fuel stock purchases.
Net cash used for investing activities totaled $234 million, $180 million, and $281 million $358 million,for 2017, 2016, and $307 million for 2015, 2014, and 2013, respectively. The changes in cash used for investing activities were primarily duerelated to gross property additions to utility plant of $247 million, $361 million,for environmental, distribution, steam generation, and $305 million for 2015, 2014, and 2013, respectively.transmission assets. Funds for the Company's property additions were provided by operating activities, capital contributions, and other financing activities.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Net cash used for financing activities totaled $150 million in 2017 primarily due to the payment of short-term debt, the payment of common stock dividends, and the redemption of preferred stock, partially offset by the proceeds of the issuance of long-term debt and common stock. Net cash used for financing activities totaled $217 million in 2016 primarily due to the redemptions of long-term debt and the payment of common stock dividends, partially offset by an increase in notes payable. Net cash used for financing activities totaled $144 million in 2015 primarily due to the payment of common stock dividends and redemptions of long-term debt, partially offset by an increase in notes payable and proceeds from the issuance of common stock to Southern Company. Net cash provided from financing activities totaled $31 million in 2014 primarily due to the issuance of long-term debt and common stock, partially offset by the payment of common stock dividends, the redemption of long-term debt and a decrease to notes payable. Net cash used for financing activities totaled $34 million in 2013 primarily due to the payment of common stock dividends and redemptions of long-term debt, partially offset by issuances of stock to Southern Company and issuances of long-term debt. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes in 20152017 primarily reflect the financing activities described above. Other significant changes, which resulted from the Tax Reform Legislation, included increases of $195 millionan increase in property, plant,deferred credits related to income taxes and equipment, primarily due to additions in generation, transmission, and distribution facilities, $110 million in securities due within one year primarily due to senior notes maturing in 2016, $96 milliona decrease in accumulated deferred income taxes primarily related to bonus depreciation,taxes. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and $96 million in AROs. Other significant changes include decreases of $169 million in long-term debtNotes 3 and $37 million in under recovered regulatory clause revenues. See Note 1 and Note 5 to the financial statements under "Retail Regulatory Matters" and "Current and Deferred Income Taxes," respectively, for additional information regarding AROs and deferred income taxes, respectively.related proposed regulatory treatment.
The Company's ratio of common equity to total capitalization includingplus short-term debt, was 46.0% in 201553.5% and 44.7% in 2014.48.3% at December 31, 2017 and 2016, respectively. See Note 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds required for construction and other purposesto meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans,borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors.
Security issuances areThe issuance of securities by the Company is subject to annual regulatory approval by the Florida PSC pursuant to its rules and regulations.PSC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the Florida PSC, as well as the amounts if any, registered under the 1933 Act, are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.
The Company obtains financing separately without credit support from any affiliate. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
The Company's current liabilities frequentlymay exceed current assets because of scheduled maturities of long-term debt and the continuedperiodic use of short-term debt as a funding source, to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs, which can fluctuate significantly dueneeds.
The Company intends to the seasonality of the business.utilize operating cash flows, external security issuances, and borrowings from financial institutions to fund its short-term capital needs. The Company has substantial cash flow from operating activities and access to the capital markets and
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.needs.
At December 31, 2015,2017, the Company had approximately $74$28 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 20152017 were as follows:
| | Expires | Expires | | Executable Term-Loans | | Due Within One Year | Expires | | Executable Term Loans | | Expires Within One Year |
2016 | 2017 | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
2018 | | 2019 | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
(in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) |
$80 | $30 | $165 | | $275 | | $275 | | $50 | | $— | | $50 | | $30 | |
$30 | | $25 | $225 | | $280 | | $280 | | $45 | | $— | | $20 | | $10 |
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In November 2015,2017, the Company amended and restated certain$195 million of its multi-year credit arrangements which, among other things, extendedto extend the maturity dates for the majority of the Company's agreements from 20162017 and 2018 to 2018.2020.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross accelerationcross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the Company. Such cross accelerationcross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrowerCompany defaulted on indebtedness, the payment of which was then accelerated. TheAt December 31, 2017, the Company is currentlywas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of the unused credit arrangements with banks are allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 20152017 was approximately $82 million. In addition, at December 31, 2015,2017, the Company had $33$75 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional electric operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable on the balance sheets.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
Details of short-term borrowings were as follows:
| | | Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) | Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2015: | | | | | | | | | | |
December 31, 2017 | | | | | | | | | | |
Commercial paper | $ | 142 |
| | 0.7 | % | | $ | 101 |
| | 0.4 | % | | $ | 175 |
| $ | 45 |
| | 2.0 | % | | $ | 20 |
| | 1.3 | % | | $ | 168 |
|
Short-term bank debt | — |
| | — | % | | 10 |
| | 0.7 | % | | 40 |
| — |
| | — | % | | 38 |
| | 1.6 | % | | 100 |
|
Total | $ | 142 |
| | 0.7 | % | | $ | 111 |
| | 0.4 | % | | | $ | 45 |
| | 2.0 | % | | $ | 58 |
| | 1.5 | % | | |
December 31, 2014: | | | | | | | | | | |
Commercial paper | $ | 110 |
| | 0.3 | % | | $ | 85 |
| | 0.2 | % | | $ | 145 |
| |
December 31, 2013: | | | | | | | | | | |
December 31, 2016 | | | | | | | | | | |
Commercial paper | $ | 136 |
| | 0.2 | % | | $ | 92 |
| | 0.2 | % | | $ | 173 |
| $ | 168 |
| | 1.1 | % | | $ | 53 |
| | 0.9 | % | | $ | 168 |
|
Short-term bank debt | — |
| | N/A |
| | 11 |
| | 1.2 | % | | 125 |
| 100 |
| | 1.5 | % | | 64 |
| | 1.3 | % | | 100 |
|
Total | $ | 136 |
| | 0.2 | % | | $ | 103 |
| | 0.3 | % | | | $ | 268 |
| | 1.2 | % | | $ | 117 |
| | 1.1 | % | | |
December 31, 2015 | | | | | | | | | | |
Commercial paper | | $ | 142 |
| | 0.7 | % | | $ | 101 |
| | 0.4 | % | | $ | 175 |
|
Short-term bank debt | | — |
| | — | % | | 10 |
| | 0.7 | % | | 40 |
|
Total | | $ | 142 |
| | 0.7 | % | | $ | 111 |
| | 0.4 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the year. |
The Company believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank term loans, and operating cash flows.
Financing Activities
In January 2015,2017, the Company issued 200,0001,750,000 shares of common stock to Southern Company and realized proceeds of $20$175 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program.
In June 2015,March 2017, the Company entered intoextended the maturity of a $40$100 million aggregate principal amount three-monthshort-term floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for credit support, working capital,LIBOR from April 2017 to October 2017 and other general corporate purposes. Thesubsequently repaid the loan was repaid at maturity.in May 2017.
In July 2015,May 2017, the Company purchased and held $13issued $300 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds (Gulf Power Company Project), Series 2012. These bonds2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were remarketedused to the public on July 16, 2015.
In September 2015, the Company redeemed $60repay at maturity $85 million aggregate principal amount of its Series L 5.65%2007A 5.90% Senior Notes due September 1, 2035.June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.
In October 2015, the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $80 million.2017 Annual Report
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
TheAt December 31, 2017, the Company doesdid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, transmission, and energy price risk management.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
The maximum potential collateral requirements under these contracts at December 31, 20152017 were as follows: | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| (in millions) | (in millions) |
At BBB- and/or Baa3 | $ | 91 |
| $ | 167 |
|
Below BBB- and/or Baa3 | $ | 467 |
| $ | 562 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On August 17, 2015,March 24, 2017, S&P downgraded therevised its consolidated long-term issuercredit rating ofoutlook for Southern Company and its subsidiaries (including the Company) to A- from A and revised its credit rating outlook from negative to stable. Separately, on August 24, 2015, S&P revised its credit rating outlook from stable to negative followingnegative.
While it is unclear how the announcementcredit rating agencies, the FERC, and the Florida PSC may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. The Company intends to work with the Florida PSC, including working towards approval of the proposed merger of a wholly-owned direct subsidiary of Southern Company with and into AGL Resources Inc.2018 Tax Reform Settlement Agreement, to mitigate the adverse impacts, if any, to certain credit metrics. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives which are designated as hedges. The weighted average interest rate on $82 million of outstanding variable rate long-term debt that has not been hedged at January 1, 2016December 31, 2017 was 0.03%1.85%. If the Company sustained a 100 basis point change in interest rates for all variable rate long-term debt, the change would not materially affect annualized interest expense at January 1, 2016.December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.
To mitigate residual risks relative to movements in fuel and electricity prices, the Company enters into financial hedge contracts for natural gas purchases and physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. The Company continues to manage a fuel-hedging program implemented per the guidelines of the Florida PSC and the actual cost of fuel is recovered through the retail fuel clause. The Florida PSC extended the moratorium on the Company's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
Company had no material change in market risk exposure for the year ended December 31, 20152017 when compared to the year ended December 31, 2014.2016.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, substantially all of which are composed of regulatory hedges, were as follows:
| | | 2015 Changes | | 2014 Changes | 2017 Changes | | 2016 Changes |
| Fair Value | Fair Value |
| (in millions) | (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (72 | ) | | $ | (10 | ) | $ | (24 | ) | | $ | (100 | ) |
Contracts realized or settled | 47 |
| | (3 | ) | 17 |
| | 49 |
|
Current period changes(*) | (75 | ) | | (59 | ) | (14 | ) | | 27 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (100 | ) | | $ | (72 | ) | $ | (21 | ) | | $ | (24 | ) |
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts were 8222 million mmBtu and 8551 million mmBtu as of December 31, 20152017 and December 31, 2014,2016, respectively.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
The weighted average swap contract cost above market prices was approximately $1.17$0.95 per mmBtu as of December 31, 20152017 and $0.80$0.48 per mmBtu as of December 31, 2014.2016. Natural gas settlements are recovered through the Company's fuel cost recovery clause.
At December 31, 20152017 and 2014,2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery clause. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred and were not material for any year presented and the actual cost of fuel is recovered through the retail fuel clause.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2.2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 20152017 were as follows:
| | | Fair Value Measurements December 31, 2015 | Fair Value Measurements December 31, 2017 |
| Total | | Maturity | Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 | | Years 4&5 | Fair Value | | Year 1 | | Years 2&3 | | Years 4&5 |
| (in millions) | (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (100 | ) | | (49 | ) | | (46 | ) | | (5 | ) | (21 | ) | | (14 | ) | | (7 | ) | | — |
|
Level 3 | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (100 | ) | | $ | (49 | ) | | $ | (46 | ) | | $ | (5 | ) | $ | (21 | ) | | $ | (14 | ) | | $ | (7 | ) | | $ | — |
|
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements.
Through 2015, capacity revenues represented the majority of the Company's wholesale earnings. The Company had long-term sales contracts to cover 100% of its ownership share of Plant Scherer Unit 3 and these capacity revenues represented 82% of total wholesale capacity revenues for 2015. Due to the expiration of a wholesale contract at the end of 2015 and future expiration dates of the remaining wholesale contracts for the unit, the Company currently has contracts to cover 34% of the unit for 2016 and 27% of the unit through 2019. Although the Company is actively evaluating alternatives relating to this asset, including replacement wholesale contracts, the expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on the Company's earnings in 2016 and may continue to have a material negative impact in future years. In the event some portion of the Company's ownership of Plant Scherer Unit 3 is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the Southern Company power pool or into the wholesale market.
Capital Requirements and Contractual Obligations
The construction program of the Company is currently estimated to total $215$304 million for 2016, $1972018, $266 million for 2017, and $1762019, $358 million for 2018.2020, $279 million for 2021, and $229 million for 2022. These amounts include capital expenditures related to contractual purchase commitments for capital expenditures covered under long-term service agreements. Estimated capital
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2017 Annual Report
expenditures to comply with environmental statuteslaws and regulations included in these amounts are $30$65 million, $43$57 million, $83 million, $58 million, and $44$16 million for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA's final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-firedfossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds at Plant Scholz and in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $16$35 million, $15$11 million, $12 million, $18 million, and $47
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 2015 Annual Report
$4 million for the years 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC and the Florida PSC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preference stock dividends, leases, pension and post-retirement benefit plans, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total |
| (in millions) |
Long-term debt(a) – | | | | | | | | | |
Principal | $ | 110 |
| | $ | 85 |
| | $ | 175 |
| | $ | 949 |
| | $ | 1,319 |
|
Interest | 54 |
| | 92 |
| | 87 |
| | 755 |
| | 988 |
|
Financial derivative obligations(b) | 49 |
| | 46 |
| | 5 |
| | — |
| | 100 |
|
Preference stock dividends(c) | 9 |
| | 18 |
| | 18 |
| | — |
| | 45 |
|
Operating leases(d) | 10 |
| | 11 |
| | — |
| | — |
| | 21 |
|
Purchase commitments – | | | | | | | | | |
Capital(e) | 188 |
| | 373 |
| | — |
| | — |
| | 561 |
|
Fuel(f) | 219 |
| | 287 |
| | 178 |
| | 107 |
| | 791 |
|
Purchased power(g) | 115 |
| | 234 |
| | 241 |
| | 910 |
| | 1,500 |
|
Other(h) | 14 |
| | 32 |
| | 34 |
| | 156 |
| | 236 |
|
Pension and other postretirement benefit plans(i) | 5 |
| | 11 |
| | — |
| | — |
| | 16 |
|
Total | $ | 773 |
| | $ | 1,189 |
| | $ | 738 |
| | $ | 2,877 |
| | $ | 5,577 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) – | | | | | | | | | |
Principal | $ | — |
| | $ | 175 |
| | $ | 141 |
| | $ | 983 |
| | $ | 1,299 |
|
Interest | 48 |
| | 95 |
| | 79 |
| | 554 |
| | 776 |
|
Financial derivative obligations(b) | 14 |
| | 7 |
| | — |
| | — |
| | 21 |
|
Operating leases(c) | 8 |
| | 4 |
| | 3 |
| | 4 |
| | 19 |
|
Purchase commitments – | | | | | | | | | |
Capital(d) | 304 |
| | 594 |
| | 508 |
| | — |
| | 1,406 |
|
Fuel(e) | 211 |
| | 247 |
| | 132 |
| | 44 |
| | 634 |
|
Purchased power(f) | 129 |
| | 266 |
| | 275 |
| | 906 |
| | 1,576 |
|
Other(g) | 16 |
| | 34 |
| | 36 |
| | 119 |
| | 205 |
|
Pension and other postretirement benefit plans(h) | 5 |
| | 11 |
| | — |
| | — |
| | 16 |
|
Total | $ | 735 |
| | $ | 1,433 |
| | $ | 1,174 |
| | $ | 2,610 |
| | $ | 5,952 |
|
| |
(a) | All amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2016,December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. |
| |
(b) | For additional information, seeSee Notes 1 and 10 to the financial statements.statements for additional information. |
| |
(c) | Preference stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(d) | Excludes a PPA accounted for as a lease, andwhich is included in purchased"Purchased power." |
| |
(e)(d) | The Company provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected in "Other." At December 31, 2015,2017, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" for additional information. |
| |
(f)(e) | Includes commitments to purchase coal and natural gas, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(g)(f) | The capacity and transmission related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Energy costs associated with PPAs are recovered through the fuel cost recovery clause. See Notes 3 and 7 to the financial statements for additional information. |
| |
(h)(g) | Includes long-term service agreements and contracts for the procurement of limestone. Long-term service agreements include price escalation based on inflation indices. Limestone costs are recovered through the environmental cost recovery clause. See Note 3 to the financial statements for additional information. |
| |
(i)(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan and postretirement benefit plans contributions, financing activities, start and completion of construction projects, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gulf Power Company 20152017 Annual Report
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Gulf Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Retail revenues | $ | 1,249 |
| | $ | 1,267 |
| | $ | 1,170 |
| $ | 1,281 |
| | $ | 1,281 |
| | $ | 1,249 |
|
Wholesale revenues, non-affiliates | 107 |
| | 129 |
| | 109 |
| 57 |
| | 61 |
| | 107 |
|
Wholesale revenues, affiliates | 58 |
| | 130 |
| | 100 |
| 108 |
| | 75 |
| | 58 |
|
Other revenues | 69 |
| | 64 |
| | 61 |
| 70 |
| | 68 |
| | 69 |
|
Total operating revenues | 1,483 |
| | 1,590 |
| | 1,440 |
| 1,516 |
| | 1,485 |
| | 1,483 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 445 |
| | 605 |
| | 533 |
| 427 |
| | 432 |
| | 445 |
|
Purchased power, non-affiliates | 100 |
| | 82 |
| | 52 |
| |
Purchased power, affiliates | 35 |
| | 25 |
| | 33 |
| |
Purchased power | | 155 |
| | 142 |
| | 135 |
|
Other operations and maintenance | 354 |
| | 341 |
| | 310 |
| 359 |
| | 336 |
| | 354 |
|
Depreciation and amortization | 141 |
| | 145 |
| | 149 |
| 137 |
| | 172 |
| | 141 |
|
Taxes other than income taxes | 118 |
| | 111 |
| | 98 |
| 116 |
| | 120 |
| | 118 |
|
Loss on Plant Scherer Unit 3 | | 33 |
| | — |
| | — |
|
Total operating expenses | 1,193 |
| | 1,309 |
| | 1,175 |
| 1,227 |
| | 1,202 |
| | 1,193 |
|
Operating Income | 290 |
| | 281 |
| | 265 |
| 289 |
| | 283 |
| | 290 |
|
Other Income and (Expense): | | | | | | | | | | |
Allowance for equity funds used during construction | 13 |
| | 12 |
| | 6 |
| |
Interest expense, net of amounts capitalized | (49 | ) | | (53 | ) | | (56 | ) | (50 | ) | | (47 | ) | | (49 | ) |
Other income (expense), net | (5 | ) | | (3 | ) | | (3 | ) | (10 | ) | | (5 | ) | | 8 |
|
Total other income and (expense) | (41 | ) | | (44 | ) | | (53 | ) | (60 | ) | | (52 | ) | | (41 | ) |
Earnings Before Income Taxes | 249 |
| | 237 |
| | 212 |
| 229 |
| | 231 |
| | 249 |
|
Income taxes | 92 |
| | 88 |
| | 80 |
| 90 |
| | 91 |
| | 92 |
|
Net Income | 157 |
| | 149 |
| | 132 |
| 139 |
| | 140 |
| | 157 |
|
Dividends on Preference Stock | 9 |
| | 9 |
| | 8 |
| 4 |
| | 9 |
| | 9 |
|
Net Income After Dividends on Preference Stock | $ | 148 |
| | $ | 140 |
| | $ | 124 |
| $ | 135 |
| | $ | 131 |
| | $ | 148 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Gulf Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Net Income | $ | 157 |
| | $ | 149 |
| | $ | 132 |
| $ | 139 |
| | $ | 140 |
| | $ | 157 |
|
Other comprehensive income (loss): | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $-, $-, and $-, respectively | 1 |
| | — |
| | — |
| |
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $-, respectively | — |
| | — |
| | 1 |
| |
Changes in fair value, net of tax of $(1), $-, and $-, respectively | | (1 | ) | | 1 |
| | 1 |
|
Total other comprehensive income (loss) | 1 |
| | — |
| | 1 |
| (1 | ) | | 1 |
| | 1 |
|
Comprehensive Income | $ | 158 |
| | $ | 149 |
| | $ | 133 |
| $ | 138 |
| | $ | 141 |
| | $ | 158 |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Gulf Power Company 20152017 Annual Report | | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Activities: | | | | | | | | | | |
Net income | $ | 157 |
| | $ | 149 |
| | $ | 132 |
| $ | 139 |
| | $ | 140 |
| | $ | 157 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization, total | 152 |
| | 153 |
| | 156 |
| 149 |
| | 179 |
| | 152 |
|
Deferred income taxes | 90 |
| | 65 |
| | 77 |
| 72 |
| | 57 |
| | 90 |
|
Allowance for equity funds used during construction | (13 | ) | | (12 | ) | | (6 | ) | |
Pension, postretirement, and other employee benefits | 10 |
| | (23 | ) | | 11 |
| |
Pension and postretirement funding | | — |
| | (48 | ) | | — |
|
Loss on Plant Scherer Unit 3 | | 33 |
| | — |
| | — |
|
Other, net | 7 |
| | 2 |
| | 9 |
| (3 | ) | | (3 | ) | | 4 |
|
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | 33 |
| | (17 | ) | | (49 | ) | (43 | ) | | 15 |
| | 33 |
|
-Fossil fuel stock | (6 | ) | | 34 |
| | 19 |
| 8 |
| | 37 |
| | (6 | ) |
-Prepaid income taxes | 32 |
| | (19 | ) | | 16 |
| 8 |
| | (11 | ) | | 32 |
|
-Other current assets | (2 | ) | | (2 | ) | | (1 | ) | (2 | ) | | (1 | ) | | (2 | ) |
-Accounts payable | (22 | ) | | 8 |
| | (7 | ) | 20 |
| | 5 |
| | (22 | ) |
-Accrued compensation | 2 |
| | 11 |
| | (3 | ) | |
-Over recovered regulatory clause revenues | 22 |
| | — |
| | (17 | ) | (12 | ) | | 1 |
| | 22 |
|
-Other current liabilities | (2 | ) | | (5 | ) | | (6 | ) | (13 | ) | | 8 |
| | — |
|
Net cash provided from operating activities | 460 |
| | 344 |
| | 331 |
| 356 |
| | 379 |
| | 460 |
|
Investing Activities: | | | | | | | | | | |
Property additions | (235 | ) | | (348 | ) | | (293 | ) | (202 | ) | | (178 | ) | | (235 | ) |
Cost of removal net of salvage | (10 | ) | | (13 | ) | | (14 | ) | |
Cost of removal, net of salvage | | (21 | ) | | (9 | ) | | (10 | ) |
Change in construction payables | (28 | ) | | 12 |
| | 7 |
| (2 | ) | | 13 |
| | (28 | ) |
Payments pursuant to long-term service agreements | (8 | ) | | (8 | ) | | (7 | ) | |
Other investing activities | — |
| | (1 | ) | | — |
| (9 | ) | | (6 | ) | | (8 | ) |
Net cash used for investing activities | (281 | ) | | (358 | ) | | (307 | ) | (234 | ) | | (180 | ) | | (281 | ) |
Financing Activities: | | | | | | | | | | |
Increase (decrease) in notes payable, net | 32 |
| | (26 | ) | | 12 |
| (223 | ) | | 126 |
| | 32 |
|
Proceeds — | | | | | | | | | | |
Common stock issued to parent | 20 |
| | 50 |
| | 40 |
| 175 |
| | — |
| | 20 |
|
Capital contributions from parent company | 4 |
| | 4 |
| | 3 |
| 2 |
| | 20 |
| | 4 |
|
Preference stock | — |
| | — |
| | 50 |
| |
Pollution control revenue bonds | 13 |
| | 42 |
| | 63 |
| — |
| | — |
| | 13 |
|
Senior notes | — |
| | 200 |
| | 90 |
| 300 |
| | — |
| | — |
|
Redemptions — | | | | | | |
Redemptions and repurchases — | | | | | | |
Preference stock | | (150 | ) | | — |
| | — |
|
Senior notes | | (85 | ) | | (235 | ) | | (60 | ) |
Pollution control revenue bonds | (13 | ) | | (29 | ) | | (76 | ) | — |
| | — |
| | (13 | ) |
Senior notes | (60 | ) | | (75 | ) | | (90 | ) | |
Payment of preference stock dividends | (9 | ) | | (9 | ) | | (7 | ) | |
Payment of common stock dividends | (130 | ) | | (123 | ) | | (115 | ) | (165 | ) | | (120 | ) | | (130 | ) |
Other financing activities | (1 | ) | | (3 | ) | | (4 | ) | (4 | ) | | (8 | ) | | (10 | ) |
Net cash provided from (used for) financing activities | (144 | ) | | 31 |
| | (34 | ) | |
Net cash used for financing activities | | (150 | ) | | (217 | ) | | (144 | ) |
Net Change in Cash and Cash Equivalents | 35 |
| | 17 |
| | (10 | ) | (28 | ) | | (18 | ) | | 35 |
|
Cash and Cash Equivalents at Beginning of Year | 39 |
| | 22 |
| | 32 |
| 56 |
| | 74 |
| | 39 |
|
Cash and Cash Equivalents at End of Year | $ | 74 |
| | $ | 39 |
| | $ | 22 |
| $ | 28 |
| | $ | 56 |
| | $ | 74 |
|
Supplemental Cash Flow Information: | | | | | | | | | | |
Cash paid (received) during the period for — | | | | | | | | | | |
Interest (net of $6, $5, and $3 capitalized, respectively) | $ | 52 |
| | $ | 48 |
| | $ | 53 |
| |
Interest (net of $-, $-, and $6 capitalized, respectively) | | $ | 46 |
| | $ | 53 |
| | $ | 52 |
|
Income taxes (net of refunds) | (7 | ) | | 44 |
| | (11 | ) | 12 |
| | 21 |
| | (7 | ) |
Noncash transactions — accrued property additions at year-end | 20 |
| | 42 |
| | 32 |
| |
Noncash transactions — | | | | | | |
Accrued property additions at year-end | | 31 |
| | 33 |
| | 20 |
|
Other financing activities related to energy services | | (7 | ) | | — |
| | — |
|
Receivables related to energy services | | 7 |
| | — |
| | — |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Gulf Power Company 20152017 Annual Report
| | Assets | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 74 |
| | $ | 39 |
| $ | 28 |
| | $ | 56 |
|
Receivables — | | | | | | |
Customer accounts receivable | 76 |
| | 73 |
| 76 |
| | 72 |
|
Unbilled revenues | 54 |
| | 58 |
| 67 |
| | 55 |
|
Under recovered regulatory clause revenues | 20 |
| | 57 |
| 27 |
| | 17 |
|
Affiliated | | 14 |
| | 17 |
|
Other accounts and notes receivable | 9 |
| | 8 |
| 7 |
| | 6 |
|
Affiliated companies | 1 |
| | 10 |
| |
Accumulated provision for uncollectible accounts | (1 | ) | | (2 | ) | (1 | ) | | (1 | ) |
Income taxes receivable, current | 27 |
| | — |
| |
Fossil fuel stock, at average cost | 108 |
| | 101 |
| |
Materials and supplies, at average cost | 56 |
| | 56 |
| |
Fossil fuel stock | | 63 |
| | 71 |
|
Materials and supplies | | 57 |
| | 55 |
|
Other regulatory assets, current | 90 |
| | 74 |
| 56 |
| | 44 |
|
Prepaid expenses | 8 |
| | 37 |
| |
Other current assets | 14 |
| | 2 |
| 21 |
| | 30 |
|
Total current assets | 536 |
| | 513 |
| 415 |
| | 422 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 5,045 |
| | 4,495 |
| 5,196 |
| | 5,140 |
|
Less accumulated provision for depreciation | 1,296 |
| | 1,296 |
| |
Less: Accumulated provision for depreciation | | 1,461 |
| | 1,382 |
|
Plant in service, net of depreciation | 3,749 |
| | 3,199 |
| 3,735 |
| | 3,758 |
|
Other utility plant, net | 62 |
| | — |
| |
Construction work in progress | 48 |
| | 465 |
| 91 |
| | 51 |
|
Total property, plant, and equipment | 3,859 |
| | 3,664 |
| 3,826 |
| | 3,809 |
|
Other Property and Investments | 4 |
| | 15 |
| |
Deferred Charges and Other Assets: | | | | | | |
Deferred charges related to income taxes | 61 |
| | 56 |
| 31 |
| | 58 |
|
Other regulatory assets, deferred | 427 |
| | 416 |
| 502 |
| | 512 |
|
Other deferred charges and assets | 33 |
| | 33 |
| 23 |
| | 21 |
|
Total deferred charges and other assets | 521 |
| | 505 |
| 556 |
| | 591 |
|
Total Assets | $ | 4,920 |
| | $ | 4,697 |
| $ | 4,797 |
| | $ | 4,822 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Gulf Power Company 20152017 Annual Report
| | Liabilities and Stockholder's Equity | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Liabilities: | | | | | | |
Securities due within one year | $ | 110 |
| | $ | — |
| $ | — |
| | $ | 87 |
|
Notes payable | 142 |
| | 110 |
| 45 |
| | 268 |
|
Accounts payable — | | | | | | |
Affiliated | 55 |
| | 87 |
| 52 |
| | 59 |
|
Other | 44 |
| | 56 |
| 75 |
| | 54 |
|
Customer deposits | 36 |
| | 35 |
| 35 |
| | 35 |
|
Accrued taxes — | | | | | | |
Accrued income taxes | 4 |
| | — |
| 1 |
| | 1 |
|
Other accrued taxes | 9 |
| | 9 |
| 9 |
| | 19 |
|
Accrued interest | 9 |
| | 11 |
| 9 |
| | 8 |
|
Accrued compensation | 25 |
| | 23 |
| 39 |
| | 40 |
|
Deferred capacity expense, current | 22 |
| | 22 |
| 22 |
| | 22 |
|
Other regulatory liabilities, current | 22 |
| | 1 |
| — |
| | 16 |
|
Liabilities from risk management activities | 49 |
| | 37 |
| |
Asset retirement obligations, current | | 37 |
| | 16 |
|
Other current liabilities | 40 |
| | 22 |
| 27 |
| | 24 |
|
Total current liabilities | 567 |
| | 413 |
| 351 |
| | 649 |
|
Long-Term Debt (See accompanying statements) | 1,193 |
| | 1,362 |
| 1,285 |
| | 987 |
|
Deferred Credits and Other Liabilities: | | | | | | |
Accumulated deferred income taxes | 893 |
| | 797 |
| 537 |
| | 948 |
|
Deferred credits related to income taxes | | 458 |
| | 2 |
|
Employee benefit obligations | 129 |
| | 121 |
| 102 |
| | 96 |
|
Deferred capacity expense | 141 |
| | 163 |
| 97 |
| | 119 |
|
Asset retirement obligations | 113 |
| | 17 |
| 105 |
| | 120 |
|
Other cost of removal obligations | 233 |
| | 235 |
| 221 |
| | 249 |
|
Other regulatory liabilities, deferred | 47 |
| | 48 |
| 43 |
| | 45 |
|
Other deferred credits and liabilities | 102 |
| | 85 |
| 67 |
| | 71 |
|
Total deferred credits and other liabilities | 1,658 |
| | 1,466 |
| 1,630 |
| | 1,650 |
|
Total Liabilities | 3,418 |
| | 3,241 |
| 3,266 |
| | 3,286 |
|
Preference Stock (See accompanying statements) | 147 |
| | 147 |
| — |
| | 147 |
|
Common Stockholder's Equity (See accompanying statements) | 1,355 |
| | 1,309 |
| 1,531 |
| | 1,389 |
|
Total Liabilities and Stockholder's Equity | $ | 4,920 |
| | $ | 4,697 |
| $ | 4,797 |
| | $ | 4,822 |
|
Commitments and Contingent Matters (See notes) |
| |
|
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 20152017 and 20142016
Gulf Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) | (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | | | | | | | | |
Long-term notes payable — | | | | | | | | | | | | | | |
5.30% due 2016 | $ | 110 |
| | $ | 110 |
| | | | | |
5.90% due 2017 | 85 |
| | 85 |
| | | | | |
2.93% to 5.90% due 2017 | | $ | — |
| | $ | 87 |
| | | | |
4.75% due 2020 | 175 |
| | 175 |
| | | | | 175 |
| | 175 |
| | | | |
3.10% to 5.75% due 2022-2051 | 640 |
| | 700 |
| | | | | |
3.10% due 2022 | | 100 |
| | 100 |
| | | | |
3.30% to 5.10% due 2027-2044 | | 715 |
| | 415 |
| | | | |
Total long-term notes payable | 1,010 |
| | 1,070 |
| | | | | 990 |
| | 777 |
| | | | |
Other long-term debt — | | | | | | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | | | | | | |
0.55% to 4.45% due 2022-2049 | 227 |
| | 240 |
| | | | | |
Variable rates (0.01% to 0.12% at 1/1/16) due 2022-2042 | 82 |
| | 69 |
| | | | | |
2.10% due 2022 | | 37 |
| | 37 |
| | | | |
1.15% to 4.45% due 2023-2049 | | 190 |
| | 190 |
| | | | |
Variable rate (1.83% at 12/31/17) due 2022 | | 4 |
| | 4 |
| | | | |
Variable rates (1.85% to 1.88% at 12/31/17) due 2039-2042 | | 78 |
| | 78 |
| | | | |
Total other long-term debt | 309 |
| | 309 |
| | | | | 309 |
| | 309 |
| | | | |
Unamortized debt discount | (8 | ) | | (9 | ) | | | | | (5 | ) | | (5 | ) | | | | |
Unamortized debt issuance expense | (8 | ) | | (8 | ) | | | | | (9 | ) | | (7 | ) | | | | |
Total long-term debt (annual interest requirement — $54 million) | 1,303 |
| | 1,362 |
| | | | | |
Total long-term debt (annual interest requirement — $48 million) | | 1,285 |
| | 1,074 |
| | | | |
Less amount due within one year | 110 |
| | — |
| | | | | — |
| | 87 |
| | | | |
Long-term debt excluding amount due within one year | 1,193 |
| | 1,362 |
| | 44.3 | % | | 48.3 | % | 1,285 |
| | 987 |
| | 45.6 | % | | 39.1 | % |
Preferred and Preference Stock: | | | | | | | | | | | | | | |
Authorized — 20,000,000 shares — preferred stock | | | | | | | | | | | | | | |
— 10,000,000 shares — preference stock | | | | | | | | | | | | | | |
Outstanding — $100 par or stated value | | | | | | | | | | | | | | |
— 6% preference stock — 550,000 shares (non-cumulative) | 54 |
| | 54 |
| | | | | |
— 2017: no shares | | | | | | | | |
— 2016: | | | | | | | | |
— 6.00% preference stock — 550,000 shares (non-cumulative) | | — |
| | 54 |
| | | | |
— 6.45% preference stock — 450,000 shares (non-cumulative) | 44 |
| | 44 |
| | | | | — |
| | 44 |
| | | | |
— 5.60% preference stock — 500,000 shares (non-cumulative) | 49 |
| | 49 |
| | | | | — |
| | 49 |
| | | | |
Total preference stock (annual dividend requirement — $9 million) | 147 |
| | 147 |
| | 5.4 |
| | 5.2 |
| |
Total preference stock | | — |
| | 147 |
| | — |
| | 5.8 |
|
Common Stockholder's Equity: | | | | | | | | | | | | | | |
Common stock, without par value — | | | | | | | | | | | | | | |
Authorized — 20,000,000 shares | | | | | | | | | | | | | | |
Outstanding — 2015: 5,642,717 shares | | | | | | | | |
— 2014: 5,442,717 shares | 503 |
| | 483 |
| | | | | |
Outstanding — 2017: 7,392,717 shares | | | | | | | | |
— 2016: 5,642,717 shares | | 678 |
| | 503 |
| | | | |
Paid-in capital | 567 |
| | 560 |
| | | | | 594 |
| | 589 |
| | | | |
Retained earnings | 285 |
| | 267 |
| | | | | 259 |
| | 296 |
| | | | |
Accumulated other comprehensive loss | — |
| | (1 | ) | | | | | |
Accumulated other comprehensive income | | — |
| | 1 |
| | | | |
Total common stockholder's equity | 1,355 |
| | 1,309 |
| | 50.3 |
| | 46.5 |
| 1,531 |
| | 1,389 |
| | 54.4 |
| | 55.1 |
|
Total Capitalization | $ | 2,695 |
| | $ | 2,818 |
| | 100.0 | % | | 100.0 | % | $ | 2,816 |
| | $ | 2,523 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 20152017, 20142016, and 20132015
Gulf Power Company 20152017 Annual Report
| | | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) | (in millions) |
Balance at December 31, 2012 | 5 |
| | $ | 393 |
| | $ | 549 |
| | $ | 241 |
| | $ | (2 | ) | | $ | 1,181 |
| |
Net income after dividends on preference stock | — |
| | — |
| | — |
| | 124 |
| | — |
| | 124 |
| |
Issuance of common stock | — |
| | 40 |
| | — |
| | — |
| | — |
| | 40 |
| |
Capital contributions from parent company | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| |
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (115 | ) | | — |
| | (115 | ) | |
Balance at December 31, 2013 | 5 |
| | 433 |
| | 553 |
| | 250 |
| | (1 | ) | | 1,235 |
| |
Net income after dividends on preference stock | — |
| | — |
| | — |
| | 140 |
| | — |
| | 140 |
| |
Issuance of common stock | — |
| | 50 |
| | — |
| | — |
| | — |
| | 50 |
| |
Capital contributions from parent company | — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (123 | ) | | — |
| | (123 | ) | |
Balance at December 31, 2014 | 5 |
| | 483 |
| | 560 |
| | 267 |
| | (1 | ) | | 1,309 |
| 5 |
| | $ | 483 |
| | $ | 560 |
| | $ | 267 |
| | $ | (1 | ) | | $ | 1,309 |
|
Net income after dividends on preference stock | — |
| | — |
| | — |
| | 148 |
| | — |
| | 148 |
| — |
| | — |
| | — |
| | 148 |
| | — |
| | 148 |
|
Issuance of common stock | 1 |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
| 1 |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
Capital contributions from parent company | — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
| — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (130 | ) | | — |
| | (130 | ) | — |
| | — |
| | — |
| | (130 | ) | | — |
| | (130 | ) |
Balance at December 31, 2015 | 6 |
| | $ | 503 |
| | $ | 567 |
| | $ | 285 |
| | $ | — |
| | $ | 1,355 |
| 6 |
| | 503 |
| | 567 |
| | 285 |
| | — |
| | 1,355 |
|
Net income after dividends on preference stock | | — |
| | — |
| | — |
| | 131 |
| | — |
| | 131 |
|
Capital contributions from parent company | | — |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Cash dividends on common stock | | — |
| | — |
| | — |
| | (120 | ) | | — |
| | (120 | ) |
Balance at December 31, 2016 | | 6 |
| | 503 |
| | 589 |
| | 296 |
| | 1 |
| | 1,389 |
|
Net income after dividends on preference stock | | — |
| | — |
| | — |
| | 135 |
| | — |
| | 135 |
|
Issuance of common stock | | — |
| | 175 |
| | — |
| | — |
| | — |
| | 175 |
|
Capital contributions from parent company | | — |
| | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
Cash dividends on common stock | | — |
| | — |
| | — |
| | (165 | ) | | — |
| | (165 | ) |
Other | | — |
| | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | | 6 |
| | $ | 678 |
| | $ | 594 |
| | $ | 259 |
| | $ | — |
| | $ | 1,531 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Gulf Power Company 20152017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Gulf Power Company 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Gulf Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of fourthe Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, SouthernLINC Wireless,Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure (as of May 9, 2016), Inc. (PowerSecure), and other direct and indirect subsidiaries. The traditional electric operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricityelectric service to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cableoptics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The equity method is used for entities in which the Company has significant influence but does not control.
The Company is subject to regulation by the FERC and the Florida PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers revises(ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed separately from revenues under ASC 606. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. The Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances in long-term debt totaling $8 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03606 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03.result in a cumulative-effect adjustment.
Leases
On May 1, 2015,In February 2016, the FASB issued ASU No. 2015-07,2016-02, Fair Value MeasurementLeases (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)842) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted,2016-02). ASU 2016-02 requires lessees to recognize on the Company elected to early adopt the guidance as of December 31, 2015balance sheet a lease liability and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the neta right-of-use asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value usingleases. ASU 2016-02 also changes the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07.recognition,
On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-current accumulated deferred
NOTES (continued)
Gulf Power Company 20152017 Annual Report
income taxes inmeasurement, and presentation of expense associated with leases and provides clarification regarding the Company'sidentification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 31, 2014 balance sheet. Other than15, 2018 and the reclassification,Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to a PPA, cellular towers, and barges where the Company is the lessee and to outdoor lighting and power distribution equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2015-172016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have ana material impact on the results of operations, financial position, or cash flows or financial condition of the Company. See NoteNotes 5 and 8 for disclosures impacted by ASU 2015-17.2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $81 million, $80 million, and $78$81 million during 2015, 2014,2017, 2016, and 2013,2015, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
NOTES (continued)
Gulf Power Company 2017 Annual Report
See Note 7 under "Operating Leases" for information on leases of cellular tower space for the Company's digital wireless communications equipment.
The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $12$11 million, $9$8 million, and $10$12 million and Mississippi Power $31 million, $26 million, and $27 million $31 million,in 2017, 2016, and $17 million in 2015, 2014, and 2013, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information.
Total power purchased from affiliates through the power pool, included in purchased power in the statements of income, totaled $15 million, $16 million, and $35 million in 2017, 2016, and 2015, respectively.
The Company has an agreement with Alabama Power under which Alabama Power has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA from a combined cycle plant located in Alabama. The transmission improvements were completed in 2014. The Company expects to pay Alabama Power approximately $12 million a year from 2016 through 2023 for these improvements. Payments by the Company to Alabama Power for the improvements were $14$11 million, $12 million, and $8$14 million in 2017, 2016, and 2015, 2014,respectively, and 2013, respectively,are expected to be approximately $10 million annually for 2018 through 2023, when the improvements.PPA expires. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff.
In 2016, the Company purchased a turbine rotor assembly from Southern Power for $6.8 million.
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2015, 2014,2017, 2016, or 2013.2015.
The traditional electric operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
NOTES (continued)
Gulf Power Company 20152017 Annual Report
Regulatory Assets and Liabilities
The Company is subject to the provisions of the FASB in accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
| | | 2015 |
| | 2014 |
| | Note | 2017 |
| | 2016 |
| | Note |
| (in millions) | | (in millions) | |
Retiree benefit plans, net | | $ | 166 |
| | $ | 160 |
| | (a,b) |
PPA charges | $ | 163 |
| | $ | 185 |
| | (j,k) | 119 |
| | 141 |
| | (b,c) |
Retiree benefit plans, net | 147 |
| | 148 |
| | (i,j) | |
Closure of ash ponds | | 80 |
| | 75 |
| | (b,d) |
Remaining book value of retired assets | | 65 |
| | 66 |
| | (e) |
Environmental remediation | | 52 |
| | 44 |
| | (b,d) |
Other regulatory assets, net | | 36 |
| | 18 |
| | (i) |
Deferred income tax charges | | 31 |
| | 56 |
| | (f) |
Deferred return on transmission upgrades | | 25 |
| | 25 |
| | (e) |
Fuel-hedging assets, net | 104 |
| | 73 |
| | (g,j) | 21 |
| | 24 |
| | (b,h) |
Deferred income tax charges | 59 |
| | 53 |
| | (a) | |
Environmental remediation | 46 |
| | 48 |
| | (h,j) | |
Loss on reacquired debt | | 17 |
| | 18 |
| | (j) |
Asset retirement obligations, net | | 13 |
| | 7 |
| | (b,f) |
Regulatory asset, offset to other cost of removal | 29 |
| | 8 |
| | (m) | — |
| | 29 |
| | (e) |
Closure of Plant Scholz ash pond | 29 |
| | — |
| | (h,j) | |
Loss on reacquired debt | 15 |
| | 16 |
| | (c) | |
Vacation pay | 10 |
| | 10 |
| | (d,j) | |
Deferred return on transmission upgrades | 10 |
| | — |
| | (m) | |
Other regulatory assets, net | 7 |
| | 9 |
| | (l) | |
Deferred income tax charges — Medicare subsidy | 2 |
| | 3 |
| | (b) | |
Under recovered regulatory clause revenues | 1 |
| | 53 |
| | (e) | |
Deferred income tax credits | | (458 | ) | | (2 | ) | | (g) |
Other cost of removal obligations | (262 | ) | | (243 | ) | | (a) | (221 | ) | | (278 | ) | | (f) |
Property damage reserve | (38 | ) | | (35 | ) | | (f) | (40 | ) | | (40 | ) | | (e) |
Over recovered regulatory clause revenues | (22 | ) | | — |
| | (e) | (11 | ) | | (23 | ) | | (k) |
Deferred income tax credits | (3 | ) | | (4 | ) | | (a) | |
Asset retirement obligations, net | (1 | ) | | (5 | ) | | (a,j) | |
Total regulatory assets (liabilities), net | $ | 296 |
| | $ | 319 |
| | $ | (105 | ) | | $ | 320 |
| |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period, which may range up to 14 years. See Note 2 for additional information. |
| |
(b) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(c) | Recovered over the life of the PPA for periods up to six years. |
| |
(d) | Recovered through the environmental cost recovery clause when the remediation or the work is performed. |
| |
(e) | Recorded and recovered or amortized as approved by the Florida PSC. |
| |
(f) | Asset retirement and removal assets and liabilities are recorded, and deferred income tax assets are recorded, recovered, and deferred income tax liabilities are amortized, over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. |
| |
(b)(g) | Recovered andDeferred income tax liabilities are amortized over periods not exceeding 14the related property lives, which may range up to 65 years. Includes the deferred tax liabilities as a result of the Tax Reform Legislation. Amortization of $71 million of the deferred tax liabilities at December 31, 2017 is expected to be determined by the Florida PSC at a later date. See Notes 3 and 5 for additional information. |
| |
(c)(h) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which currently do not exceed four years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. |
| |
(i) | Comprised primarily of under recovered regulatory clause revenues. Other regulatory assets costs, with the exception of vacation pay, are recorded and recovered or amortized as approved by the Florida PSC. Vacation pay, including banked holiday pay, does not earn a return as offset in rate base by a corresponding liability; it is recorded as earned by employees and recovered as paid, generally within one year. |
| |
(j) | Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. |
| |
(d) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(e)(k) | Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. |
| |
(f) | Recorded and recovered or amortized as approved by the Florida PSC. |
| |
(g) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. |
| |
(h) | Recovered through the environmental cost recovery clause when the remediation or the work is performed. |
| |
(i) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. |
| |
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(k) | Recovered over the life of the PPA for periods up to eight years. |
| |
(l) | Comprised primarily of net book value of retired meters and recovery of injuries and damages costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years. |
| |
(m) | Recorded as authorized by the Florida PSC in the settlement agreement approved in December 2013 (2013 Rate Case Settlement Agreement). See Note 3 for additional information. |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any
NOTES (continued)
Gulf Power Company 2015 Annual Report
impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information.
NOTES (continued)
Gulf Power Company 2017 Annual Report
Revenues
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information.
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Company's property, plant, and equipment in service consisted of the following at December 31:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Generation | $ | 2,974 |
| | $ | 2,638 |
| $ | 3,005 |
| | $ | 3,001 |
|
Transmission | 691 |
| | 516 |
| 720 |
| | 706 |
|
Distribution | 1,196 |
| | 1,157 |
| 1,282 |
| | 1,241 |
|
General | 182 |
| | 182 |
| 188 |
| | 191 |
|
Plant acquisition adjustment | 2 |
| | 2 |
| 1 |
| | 1 |
|
Total plant in service | $ | 5,045 |
| | $ | 4,495 |
| $ | 5,196 |
| | $ | 5,140 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed.
On February 6, 2015, the Company announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016, as a result of the cost to comply with environmental regulations imposed by the EPA. In connection with this
NOTES (continued)
Gulf Power Company 2015 Annual Report
retirement, the Company reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. The net book value of these units at December 31, 2015 was approximately $62 million.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.5% in 2015 and 3.6% in both 2014 and 2013.for all years presented. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of
NOTES (continued)
Gulf Power Company 2017 Annual Report
in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized in a settlement agreement approved by the Florida PSC in the 2013 (2013 Rate Case Settlement Agreement,Agreement), the Company iswas allowed to reduce depreciation and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case"Cases" for additional information.
Asset Retirement Obligations and Other Costs of Removal
Asset retirement obligations (ARO)AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17,in 2015 (CCR Rule), principally ash ponds, and to the closure of an ash pond at Plant Scholz. In addition, the Company has retirement obligations related to combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets.
Details of the AROs included inon the balance sheets are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Balance at beginning of year | $ | 17 |
| | $ | 16 |
| $ | 136 |
| | $ | 130 |
|
Liabilities incurred | 105 |
| | — |
| — |
| | 1 |
|
Liabilities settled | (1 | ) | | — |
| (8 | ) | | (1 | ) |
Accretion | 2 |
| | 1 |
| 2 |
| | 4 |
|
Cash flow revisions | 7 |
| | — |
| 12 |
| | 2 |
|
Balance at end of year | $ | 130 |
| | $ | 17 |
| $ | 142 |
| | $ | 136 |
|
The increase in liabilities incurred in 2015 is primarily related to AROs associated with the portion of the Company's steam generation facilities impacted by the CCR Rule. The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 20152017 using various assumptions related to closure in place and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure.closure for those facilities impacted by the CCR Rule. As further
NOTES (continued)
Gulf Power Company 2015 Annual Report
analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.
In connection with permitting activity related to the coal ash pond at the retired Plant Scholz facility, the Company recorded additional AROs of $29 million.cost estimates as necessary.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, theThe Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for both 2015 and 2014 and 6.26% for 2013.all years presented. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 10.80%0.07%, 10.93%0.00%, and 6.87%10.8% for 20152017, 20142016, and 20132015, respectively.
NOTES (continued)
Gulf Power Company 2017 Annual Report
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Property Damage Reserve
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48 million and $55 million. TheIn accordance with a settlement agreement approved by the Florida PSC also authorizedon April 4, 2017 (2017 Rate Case Settlement Agreement), the Company suspended further property damage reserve accruals effective April 2017. The Company may make discretionary accruals and is required to make additionalresume accruals above theof $3.5 million atannually if the Company's discretion.reserve falls below zero. The Company accrued total expenses of $3.5 million in each of 2015, 2014,2017, 2016, and 2013.2015. As of December 31, 20152017 and 2014,2016, the balance in the Company's property damage reserve totaled approximately $38$40 million, and $35 million, respectively, which is included in other regulatory liabilities, deferred liabilities inon the balance sheets.
When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. As authorized in the 20132017 Rate Case Settlement Agreement, the Company may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center throughor other catastrophic storm events that reduce the initiationproperty damage reserve in the aggregate by approximately $31 million (75% of a storm surcharge.the April 1, 2017 balance) or more. The storm surcharge willwould begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 KWHs on monthly residential bills in aggregatepetition, would be limited to $4.00/month for a calendar year. This limitation does not apply if1,000 KWH residential customer unless the Company incurs in excess of $100 million in qualified storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary toyear, and would replenish the stormproperty damage reserve to the level that existed as of December 31, 2013.approximately $40 million. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case"Cases" for additional details of the 20132017 Rate Case Settlement Agreement.
Injuries and Damages Reserve
The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was zero at December 31, 2015 and had a balance of $4.0$2.1 million and $1.4 million at December 31, 2014. Included in current liabilities2017, and deferred credits and other liabilities in the balance sheets at December 31, 2014 is2016, respectively. For 2017, $1.6 million and $2.4 million, respectively. The Company recorded a liability with a corresponding regulatory asset of $1.7 million for estimated liabilities related to outstanding claims and suits in excess of the reserve balance at December 31, 2015, of which $1.6 million and $0.1$0.5 million are included in other current liabilities and other deferred
NOTES (continued)
Gulf Power Company 2015 Annual Report
credits and other liabilities inon the balance sheets,sheet, respectively. For 2016, the $1.4 million balance is included in other current liabilities on the balance sheet. There were no liabilities in excess of the reserve balance at December 31, 2014.2017 or 2016.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is chargedrecorded to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are
NOTES (continued)
Gulf Power Company 2017 Annual Report
recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. The Florida PSC extended the moratorium on the Company's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. See Note 10 for additional information regarding derivatives.
The Company does not offsetoffsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015.2017.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016.2018. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2016,2018, no other postretirement trust contributions are expected.
NOTES (continued)
Gulf Power Company 2015 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
NOTES (continued)
Gulf Power Company 2017 Annual Report
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2015 | | 2014 | | 2013 |
Pension plans | | | | | |
Discount rate – interest costs | 4.18 | % | | 5.02 | % | | 4.27 | % |
Discount rate – service costs | 4.48 |
| | 5.02 |
| | 4.27 |
|
Expected long-term return on plan assets | 8.20 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – interest costs | 4.04 | % | | 4.86 | % | | 4.06 | % |
Discount rate – service costs | 4.38 |
| | 4.86 |
| | 4.06 |
|
Expected long-term return on plan assets | 8.07 |
| | 8.08 |
| | 8.04 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
| | Assumptions used to determine benefit obligations: | 2015 |
| 2014 | |
Assumptions used to determine net periodic costs: | | 2017 | | 2016 | | 2015 |
Pension plans |
|
|
| | | | | |
Discount rate | 4.71 | % |
| 4.18 | % | |
Discount rate – benefit obligations | | 4.46 | % | | 4.71 | % | | 4.18 | % |
Discount rate – interest costs | | 3.82 |
| | 3.97 |
| | 4.18 |
|
Discount rate – service costs | | 4.81 |
| | 5.04 |
| | 4.48 |
|
Expected long-term return on plan assets | | 7.95 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.46 |
| | 4.46 |
| | 3.59 |
|
Other postretirement benefit plans |
|
|
| | | | | |
Discount rate | 4.51 | % |
| 4.04 | % | |
Discount rate – benefit obligations | | 4.25 | % | | 4.51 | % | | 4.04 | % |
Discount rate – interest costs | | 3.56 |
| | 3.68 |
| | 4.04 |
|
Discount rate – service costs | | 4.62 |
| | 4.88 |
| | 4.38 |
|
Expected long-term return on plan assets | | 7.81 |
| | 8.05 |
| | 8.07 |
|
Annual salary increase | 4.46 |
|
| 3.59 |
| 4.46 |
| | 4.46 |
| | 3.59 |
|
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 |
| 2016 |
Pension plans |
|
|
|
Discount rate | 3.82 | % |
| 4.46 | % |
Annual salary increase | 4.46 |
|
| 4.46 |
|
Other postretirement benefit plans |
|
|
|
Discount rate | 3.69 | % |
| 4.25 | % |
Annual salary increase | 4.46 |
|
| 4.46 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seveneight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables for its pension and other postretirement benefit plans, which reflect decreased life expectancies in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $9 million and $1 million, respectively.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 20152017 were as follows:
| | | | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | | 6.50 | % | | 4.50 | % | | 2024 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | | 5.50 |
| | 4.50 |
| | 2024 | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | | 10.00 |
| | 4.50 |
| | 2025 | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 4 |
| | $ | 3 |
|
Service and interest costs | — |
| | — |
|
NOTES (continued)
Gulf Power Company 20152017 Annual Report
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2015 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 4 |
| | $ | (3 | ) |
Service and interest costs | — |
| | — |
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $424$524 million at December 31, 20152017 and $438460 million at December 31, 20142016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 491 |
| | $ | 395 |
| $ | 517 |
| | $ | 480 |
|
Service cost | 12 |
| | 10 |
| 13 |
| | 12 |
|
Interest cost | 20 |
| | 19 |
| 19 |
| | 19 |
|
Benefits paid | (20 | ) | | (16 | ) | (20 | ) | | (17 | ) |
Actuarial loss (gain) | (23 | ) | | 83 |
| |
Actuarial (gain) loss | | 58 |
| | 23 |
|
Balance at end of year | 480 |
| | 491 |
| 587 |
| | 517 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 435 |
| | 386 |
| 491 |
| | 420 |
|
Actual return on plan assets | 4 |
| | 34 |
| |
Actual return (loss) on plan assets | | 81 |
| | 39 |
|
Employer contributions | 1 |
| | 31 |
| 1 |
| | 49 |
|
Benefits paid | (20 | ) | | (16 | ) | (20 | ) | | (17 | ) |
Fair value of plan assets at end of year | 420 |
| | 435 |
| 553 |
| | 491 |
|
Accrued liability | $ | (60 | ) | | $ | (56 | ) | $ | (34 | ) | | $ | (26 | ) |
At December 31, 20152017, the projected benefit obligations for the qualified and non-qualified pension plans were $457$563 million and $23$25 million, respectively. All pension plan assets are related to the qualified pension plan.
Amounts recognized inon the balance sheets at December 31, 20152017 and 20142016 related to the Company's pension plans consist of the following:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Other regulatory assets, deferred | $ | 142 |
| | $ | 146 |
| $ | 160 |
| | $ | 153 |
|
Current liabilities, other | (1 | ) | | (1 | ) | |
Other current liabilities | | (1 | ) | | (1 | ) |
Employee benefit obligations | (59 | ) | | (55 | ) | (33 | ) | | (25 | ) |
NOTES (continued)
Gulf Power Company 2015 Annual Report
Presented below are the amounts included in regulatory assets at December 31, 20152017 and 20142016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2016.2018.
| | | 2015 | | 2014 | | Estimated Amortization in 2016 | 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) | (in millions) |
Prior service cost | $ | 2 |
| | $ | 3 |
| | $ | 1 |
| $ | 2 |
| | $ | 3 |
| | $ | — |
|
Net loss | 140 |
| | 143 |
| | 6 |
| |
Net (gain) loss | | 158 |
| | 150 |
| | 10 |
|
Regulatory assets | $ | 142 |
| | $ | 146 |
| | | $ | 160 |
| | $ | 153 |
| | |
NOTES (continued)
Gulf Power Company 2017 Annual Report
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 20152017 and 20142016 are presented in the following table:
| |
| 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Regulatory assets: |
|
| |
|
|
|
| |
|
|
Beginning balance | $ | 146 |
| | $ | 75 |
| $ | 153 |
| | $ | 142 |
|
Net (gain) loss | 6 |
| | 77 |
| 15 |
| | 16 |
|
Change in prior service costs | | — |
| | 2 |
|
Reclassification adjustments: |
| |
|
| |
|
Amortization of prior service costs | (1 | ) | | (1 | ) | (1 | ) | | (1 | ) |
Amortization of net gain (loss) | (9 | ) | | (5 | ) | (7 | ) | | (6 | ) |
Total reclassification adjustments | (10 | ) | | (6 | ) | (8 | ) | | (7 | ) |
Total change | (4 | ) | | 71 |
| 7 |
| | 11 |
|
Ending balance | $ | 142 |
| | $ | 146 |
| $ | 160 |
| | $ | 153 |
|
Components of net periodic pension cost were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Service cost | $ | 12 |
| | $ | 10 |
| | $ | 11 |
| $ | 13 |
| | $ | 12 |
| | $ | 12 |
|
Interest cost | 20 |
| | 19 |
| | 17 |
| 19 |
| | 19 |
| | 20 |
|
Expected return on plan assets | (32 | ) | | (28 | ) | | (26 | ) | (38 | ) | | (34 | ) | | (32 | ) |
Recognized net loss | 9 |
| | 5 |
| | 9 |
| |
Recognized net (gain) loss | | 7 |
| | 6 |
| | 9 |
|
Net amortization | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
Net periodic pension cost | $ | 10 |
| | $ | 7 |
| | $ | 12 |
| $ | 2 |
| | $ | 4 |
| | $ | 10 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Gulf Power Company 2015 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2015,2017, estimated benefit payments were as follows:
| | | Benefit Payments | Benefit Payments |
| (in millions) | (in millions) |
2016 | $ | 19 |
| |
2017 | 20 |
| |
2018 | 21 |
| $ | 22 |
|
2019 | 22 |
| 23 |
|
2020 | 24 |
| 25 |
|
2021 to 2025 | 139 |
| |
2021 | | 26 |
|
2022 | | 28 |
|
2023 to 2027 | | 155 |
|
NOTES (continued)
Gulf Power Company 2017 Annual Report
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 20152017 and 20142016 were as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of year | $ | 78 |
| | $ | 69 |
| $ | 83 |
| | $ | 81 |
|
Service cost | 1 |
| | 1 |
| 1 |
| | 1 |
|
Interest cost | 3 |
| | 3 |
| 3 |
| | 3 |
|
Benefits paid | (4 | ) | | (4 | ) | (5 | ) | | (4 | ) |
Actuarial loss (gain) | (1 | ) | | 11 |
| |
Plan amendment | 4 |
| | (2 | ) | |
Retiree drug subsidy | — |
| | — |
| |
Actuarial (gain) loss | | 1 |
| | 2 |
|
Balance at end of year | 81 |
| | 78 |
| 83 |
| | 83 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of year | 18 |
| | 17 |
| 18 |
| | 17 |
|
Actual return on plan assets | — |
| | 2 |
| |
Actual return (loss) on plan assets | | 3 |
| | 2 |
|
Employer contributions | 3 |
| | 3 |
| 4 |
| | 3 |
|
Benefits paid | (4 | ) | | (4 | ) | (5 | ) | | (4 | ) |
Fair value of plan assets at end of year | 17 |
| | 18 |
| 20 |
| | 18 |
|
Accrued liability | $ | (64 | ) | | $ | (60 | ) | $ | (63 | ) | | $ | (65 | ) |
Amounts recognized inon the balance sheets at December 31, 20152017 and 20142016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 10 |
| | $ | 6 |
|
Current liabilities, other | (1 | ) | | (1 | ) |
Other regulatory liabilities, deferred | (5 | ) | | (4 | ) |
Employee benefit obligations | (63 | ) | | (59 | ) |
NOTES (continued)
Gulf Power Company 2015 Annual Report
Presented below are the amountsApproximately $6 million and $7 million was included in net regulatory assets (liabilities) at December 31, 20152017 and 20142016, respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with thecost. The estimated amortization of such amounts for 2016.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | Estimated Amortization in 2016 |
| (in millions) |
Prior service cost | $ | — |
| | $ | (2 | ) | | $ | — |
|
Net loss | 5 |
| | 4 |
| | — |
|
Net regulatory assets (liabilities) | $ | 5 |
| | $ | 2 |
| | |
2018 is immaterial.The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 20152017 and 20142016 are presented in the following table:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Net regulatory assets (liabilities): |
|
| |
|
|
Beginning balance | $ | 2 |
| | $ | (7 | ) |
Net (gain) loss | 1 |
| | 11 |
|
Change in prior service costs | 2 |
| | (2 | ) |
Reclassification adjustments: |
|
| |
|
|
Amortization of prior service costs | — |
| | — |
|
Amortization of net gain (loss) | — |
| | — |
|
Total reclassification adjustments | — |
| | — |
|
Total change | 3 |
| | 9 |
|
Ending balance | $ | 5 |
| | $ | 2 |
|
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Net regulatory assets (liabilities): |
|
| |
|
|
Beginning balance | $ | 7 |
| | $ | 5 |
|
Net (gain) loss | (1 | ) | | 2 |
|
Ending balance | $ | 6 |
| | $ | 7 |
|
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Service cost | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 3 |
| | 3 |
| | 3 |
|
Expected return on plan assets | (1 | ) | | (1 | ) | | (1 | ) |
Net amortization | — |
| | — |
| | — |
|
Net periodic postretirement benefit cost | $ | 3 |
| | $ | 3 |
| | $ | 3 |
|
NOTES (continued)
Gulf Power Company 20152017 Annual Report
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 3 |
| | 3 |
| | 3 |
|
Expected return on plan assets | (1 | ) | | (1 | ) | | (1 | ) |
Net periodic postretirement benefit cost | $ | 3 |
| | $ | 3 |
| | $ | 3 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
| | | Benefit Payments | | Subsidy Receipts | | Total | Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) | (in millions) |
2016 | $ | 5 |
| | $ | — |
| | $ | 5 |
| |
2017 | 5 |
| | — |
| | 5 |
| |
2018 | 6 |
| | — |
| | 6 |
| $ | 5 |
| | $ | — |
| | $ | 5 |
|
2019 | 6 |
| | (1 | ) | | 5 |
| 5 |
| | — |
| | 5 |
|
2020 | 6 |
| | (1 | ) | | 5 |
| 5 |
| | — |
| | 5 |
|
2021 to 2025 | 29 |
| | (3 | ) | | 26 |
| |
2021 | | 6 |
| | (1 | ) | | 5 |
|
2022 | | 6 |
| | (1 | ) | | 5 |
|
2023 to 2027 | | 28 |
| | (2 | ) | | 26 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
NOTES (continued)
Gulf Power Company 2017 Annual Report
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 20152017 and 20142016, along with the targeted mix of assets for each plan, is presented below:
| | | Target | | 2015 | | 2014 | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | | | | | |
Domestic equity | 26 | % | | 30 | % | | 30 | % | 26 | % | | 31 | % | | 29 | % |
International equity | 25 |
| | 23 |
| | 23 |
| 25 |
| | 25 |
| | 22 |
|
Fixed income | 23 |
| | 23 |
| | 27 |
| 23 |
| | 24 |
| | 29 |
|
Special situations | 3 |
| | 2 |
| | 1 |
| 3 |
| | 1 |
| | 2 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
| 14 |
| | 13 |
| | 13 |
|
Private equity | 9 |
| | 6 |
| | 5 |
| 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | | | | | | |
Domestic equity | 25 | % | | 29 | % | | 29 | % | 25 | % | | 30 | % | | 28 | % |
International equity | 24 |
| | 22 |
| | 22 |
| 24 |
| | 24 |
| | 21 |
|
Domestic fixed income | 25 |
| | 25 |
| | 29 |
| 25 |
| | 26 |
| | 31 |
|
Special situations | 3 |
| | 2 |
| | 1 |
| 3 |
| | 1 |
| | 2 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
| 14 |
| | 13 |
| | 13 |
|
Private equity | 9 |
| | 6 |
| | 5 |
| 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal
NOTES (continued)
Gulf Power Company 2015 Annual Report
rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 20152017 and 20142016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management
NOTES (continued)
Gulf Power Company 2017 Annual Report
relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and private equity.special situations investments. Investments in real estate, private equity, and real estatespecial situations are generally classified as Level 3Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniquesTechniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally useanalysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments.appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets.assets less liabilities.
NOTES (continued)
Gulf Power Company 2015 Annual Report
The fair values of pension plan assets as of December 31, 20152017 and 20142016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Domestic equity* | $ | 73 |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | 104 |
| |
International equity* | 54 |
| | 45 |
| | — |
| | — |
| | 99 |
| |
Domestic equity(*) | | $ | 112 |
| | $ | 54 |
| | $ | — |
| | $ | — |
| | $ | 166 |
|
International equity(*) | | 72 |
| | 65 |
| | — |
| | — |
| | 137 |
|
Fixed income: | | | | | | | | | | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 21 |
| | — |
| | — |
| | 21 |
| — |
| | 39 |
| | — |
| | — |
| | 39 |
|
Mortgage- and asset-backed securities | — |
| | 9 |
| | — |
| | — |
| | 9 |
| |
Corporate bonds | — |
| | 51 |
| | — |
| | — |
| | 51 |
| — |
| | 57 |
| | — |
| | — |
| | 57 |
|
Pooled funds | — |
| | 23 |
| | — |
| | — |
| | 23 |
| — |
| | 30 |
| | — |
| | — |
| | 30 |
|
Cash equivalents and other | — |
| | 7 |
| | — |
| | — |
| | 7 |
| 10 |
| | — |
| | — |
| | — |
| | 10 |
|
Real estate investments | 14 |
| | — |
| | — |
| | 55 |
| | 69 |
| 22 |
| | — |
| | — |
| | 55 |
| | 77 |
|
Special situations | | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Private equity | — |
| | — |
| | — |
| | 29 |
| | 29 |
| — |
| | — |
| | — |
| | 31 |
| | 31 |
|
Total | $ | 141 |
| | $ | 187 |
| | $ | — |
| | $ | 84 |
| | $ | 412 |
| $ | 216 |
| | $ | 245 |
| | $ | — |
| | $ | 94 |
| | $ | 555 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Gulf Power Company 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 77 |
| | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | 109 |
|
International equity* | 48 |
| | 44 |
| | — |
| | — |
| | 92 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 31 |
| | — |
| | — |
| | 31 |
|
Mortgage- and asset-backed securities | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Corporate bonds | — |
| | 51 |
| | — |
| | — |
| | 51 |
|
Pooled funds | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Cash equivalents and other | — |
| | 30 |
| | — |
| | — |
| | 30 |
|
Real estate investments | 13 |
| | — |
| | — |
| | 50 |
| | 63 |
|
Private equity | — |
| | — |
| | — |
| | 26 |
| | 26 |
|
Total | $ | 138 |
| | $ | 219 |
| | $ | — |
| | $ | 76 |
| | $ | 433 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 93 |
| | $ | 43 |
| | $ | — |
| | $ | — |
| | $ | 136 |
|
International equity(*) | 57 |
| | 52 |
| | — |
| | — |
| | 109 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 27 |
| | — |
| | — |
| | 27 |
|
Mortgage- and asset-backed securities | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Corporate bonds | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
Pooled funds | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
Cash equivalents and other | 46 |
| | — |
| | — |
| | — |
| | 46 |
|
Real estate investments | 14 |
| | — |
| | — |
| | 53 |
| | 67 |
|
Special situations | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Private equity | — |
| | — |
| | — |
| | 25 |
| | 25 |
|
Total | $ | 210 |
| | $ | 194 |
| | $ | — |
| | $ | 86 |
| | $ | 490 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Gulf Power Company 2015 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 20152017 and 20142016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | | | | | |
Domestic equity* | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | ��� |
| | $ | 4 |
| |
International equity* | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
| |
Domestic equity(*) | | $ | 4 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
International equity(*) | | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
| — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Mortgage- and asset-backed securities | — |
| | — |
| | — |
| | — |
| | — |
| |
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
| — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
| — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 1 |
| | — |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
| 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
| — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 7 |
| | $ | 7 |
| | $ | — |
| | $ | 3 |
| | $ | 17 |
| $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | 3 |
| | $ | 19 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Gulf Power Company 20152017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
International equity* | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Mortgage- and asset-backed securities | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 6 |
| | $ | 9 |
| | $ | — |
| | $ | 3 |
| | $ | 18 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 3 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
International equity(*) | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | 3 |
| | $ | 19 |
|
|
| |
*(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up tomatches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017, 2016, and 2015 2014,were $5 million, $5 million, and 2013 were $4 million, each year.respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of natural resources has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
Environmental Matters
Environmental Remediation
The Company must comply with environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually.
The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable.probable and reasonably estimable. At December 31, 20152017, and 2016, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $46$52 million and $44 million, respectively, of which approximately $4 million is included in under recovered regulatory clause revenues and other
NOTES (continued)
Gulf Power Company 20152017 Annual Report
$5 million and $4 million, respectively, is included in under recovered regulatory clause revenues and other current liabilities and approximately $42$47 million and $40 million, respectively, is included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income.
The final outcome of these matters cannot be determined at this time. However, basedthe final disposition of these matters is not expected to have a material impact on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Retail Regulatory Matters
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates.
Retail Base Rate CaseCases
In 2013, the Florida PSC voted to approve the 2013 Rate Case Settlement Agreement among the Company and all of the intervenors to the Company's retail base rate case. Under the terms of the 2013 Rate Case Settlement Agreement, the Company (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its currentFlorida PSC authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first.
The 2013 Rate Case Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized retail ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period.
The 2013 Rate Case Settlement Agreement also provides that the Company mayto reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million betweenfrom January 2014 andthrough June 2017. In any given month, such depreciation expense reduction maywas not to exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's next base rate case or next depreciationFor 2014 and dismantlement study proceeding, whichever comes first. For 2015, and 2014, the Company recognized reductions in depreciation expense of $20.1 million and $8.4 million respectively.
Pursuant to the 2013 Rate Case Settlement Agreement, the Company may not request an increase in its retail base rates to be effective until after June 2017, unless the Company's actual retail ROE falls below the authorized ROE range.
Cost Recovery Clauses
On November 2, 2015, the Florida PSC approved the Company's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2016. The net effect of the approved changes is an expected $49
NOTES (continued)
Gulf Power Company 20152017 Annual Report
and $20.1 million, decreaserespectively. No net reduction in depreciation was recorded in 2016. In 2017, the Company recognized the remaining $34.0 million reduction in depreciation.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among the Company and three intervenors with respect to the Company's request in 2016 to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, the Company increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual revenuebase revenues, less an annual purchased power capacity cost recovery clause credit for 2016. The decreasedcertain wholesale revenues will notof approximately $8 million through December 2019. In addition, the Company continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have a significant impact on net income since mostmaximum equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. The Company also began amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and implemented new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of the Company's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of the Company's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause.
The 2017 Rate Case Settlement Agreement set forth a process for addressing the revenue requirement effects of the Tax Reform Legislation through a prospective change to the Company's base rates. Under the terms of the 2017 Rate Case Settlement Agreement, by March 1, 2018, the Company must identify the revenue requirements impacts and defer them to a regulatory asset or regulatory liability to be considered for prospective application in a change to base rates in a limited scope proceeding before the Florida PSC. In lieu of this approach, on February 14, 2018, the parties to the 2017 Rate Case Settlement Agreement filed a new stipulation and settlement agreement (2018 Tax Reform Settlement Agreement) with the Florida PSC. If approved, the 2018 Tax Reform Settlement Agreement will result in annual reductions of $18.2 million to the Company's base rates and $15.6 million to the Company's environmental cost recovery rates effective beginning the first calendar month following approval.
The 2018 Tax Reform Settlement Agreement also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through the Company's fuel cost recovery rate over the remainder of 2018. In addition, a limited scope proceeding to address the flow back of protected deferred tax liabilities will be initiated by May 1, 2018 and the Company will record a regulatory liability for the related 2018 amounts eligible to be returned to customers consistent with IRS normalization principles. Unless otherwise agreed to by the parties to the 2018 Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through the Company's fuel cost recovery rate.
If the 2018 Tax Reform Settlement Agreement is approved, the 2017 Rate Case Settlement Agreement will be amended to increase the Company's maximum equity ratio from 52.5% to 53.5% for regulatory purposes.
The ultimate outcome of these matters cannot be determined at this time.
Cost Recovery Clauses
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to the Company's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.
On October 25, 2017, the Florida PSC approved the Company's annual clause rate request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by lower expenses.related expense increases.
Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment.
Retail Fuel Cost Recovery
The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested.
NOTES (continued)
Gulf Power Company 2017 Annual Report
At December 31, 2015, the over recovered fuel balance was approximately $18 million, which is included in other regulatory liabilities, current in the balance sheets. At December 31, 2014,2017, the under recovered fuel balance was approximately $40$22 million, which is included in under recovered regulatory clause revenues inon the balance sheets.sheet. At December 31, 2016, the over recovered fuel balance was approximately $15 million, which is included in other regulatory liabilities, current on the balance sheet.
Purchased Power Capacity Recovery
The Company has established purchased power capacity cost recovery cost rates as approved by the Florida PSC. If the projected year-end purchased power capacity cost over or under recovery balance exceeds 10% of the projected purchased power capacity revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the purchased power capacity cost recovery factor is being requested.
At December 31, 20152017 and 2014,, the under recovered purchased power capacity balance was $2 million, which is included in under recovered regulatory clause revenues on the balance sheet. At December 31, 2016, the balance was immaterial.
Environmental Cost Recovery
The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA.
In 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and state regulations addressing air quality. The Company's environmental compliance plan as filed in 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The Florida PSC's approval of the stipulation also required the Company to file annual updates to the plan and outlined a process for approval of additional elements in the plan when they became committed projects. In the 2010 update filing, the Company identified several elements of the updated plan that the Company had decided to implement. Following the process outlined in the original approved stipulation, these additional projects were approved by the Florida PSC later in 2010. The Florida PSC acknowledged that the costs of the approved projects associated with the Company's Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause.
Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 20152017, and 2016, the underover recovered environmental balance was immaterial. At December 31, 2014,of approximately $11 million and $8 million, respectively, along with the under recoveredcurrent portion of projected environmental balanceexpenditures, was approximately $10 million, which is included in under recovered regulatory clause revenues inon the balance sheets.
In 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The total cost of the project was approximately $653 million, with the Company's portion being approximately $316 million, excluding AFUDC. The Company's portion of the cost is being recovered through the environmental cost recovery clause.
Energy Conservation Cost Recovery
Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the energy conservation cost recovery (ECCR) clause.
NOTES (continued)
Gulf Power Company 2015 Annual Report
At December 31, 20152017, the overunder recovered ECCR balance was immaterial. At December 31, 2016, the balance was approximately $4 million, which is included in other regulatory liabilities, current in the balance sheet. At December 31, 2014, the under recovered ECCR balance was approximately $3 million, which is included in under recovered regulatory clause revenues inon the balance sheet.
Other Matters
As a result of the cost to comply with environmental regulations imposed by the EPA, the Company retired its coal-fired generation at Plant Smith Units 1 and 2 in March 2016. In August 2016, the Florida PSC approved the Company's request to reclassify the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date, totaling approximately $63 million, to a regulatory asset. The Company began amortizing the investment balances over 15 years effective January 1, 2018 in accordance with the 2017 Rate Case Settlement Agreement.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units.
The Company and Georgia Power jointly own the 818 MWs818-MW capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit.
NOTES (continued)
Gulf Power Company 2017 Annual Report
At December 31, 20152017, the Company's percentage ownership and investment in these jointly-owned facilities were as follows:
| | | Plant Scherer Unit 3 (coal) | | Plant Daniel Units 1 & 2 (coal) | Plant Scherer Unit 3 (coal) | | Plant Daniel Units 1 & 2 (coal) |
| (in millions) | (in millions) |
Plant in service | $ | 395 |
| | $ | 669 |
| $ | 374 |
| | $ | 696 |
|
Accumulated depreciation | 136 |
| | | 184 |
| 147 |
| | | 225 |
|
Construction work in progress | 2 |
| | | 9 |
| 9 |
| | | 4 |
|
Company Ownership | 25 | % | | 50 | % | |
Company ownership | | 25 | % | | 50 | % |
The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Retail Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Federal - | | | | | | | | | | |
Current | $ | (3 | ) | | $ | 23 |
| | $ | 5 |
| $ | 19 |
| | $ | 34 |
| | $ | (3 | ) |
Deferred | 80 |
| | 52 |
| | 63 |
| 58 |
| | 45 |
| | 80 |
|
| 77 |
| | 75 |
| | 68 |
| 77 |
| | 79 |
| | 77 |
|
State - | | | | | | | | | | |
Current | 5 |
| | — |
| | (2 | ) | (1 | ) | | — |
| | 5 |
|
Deferred | 10 |
| | 13 |
| | 14 |
| 14 |
| | 12 |
| | 10 |
|
| 15 |
| | 13 |
| | 12 |
| 13 |
| | 12 |
| | 15 |
|
Total | $ | 92 |
| | $ | 88 |
| | $ | 80 |
| $ | 90 |
| | $ | 91 |
| | $ | 92 |
|
NOTES (continued)
Gulf Power Company 20152017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Deferred tax liabilities- | | | | | | |
Accelerated depreciation | $ | 812 |
| | $ | 777 |
| $ | 552 |
| | $ | 834 |
|
Property basis differences | 133 |
| | 52 |
| 105 |
| | 123 |
|
Fuel recovery clause | — |
| | 16 |
| |
Pension and other employee benefits | 39 |
| | 34 |
| 38 |
| | 58 |
|
Regulatory assets | | 22 |
| | 45 |
|
Regulatory assets associated with employee benefit obligations | 59 |
| | 60 |
| 44 |
| | 65 |
|
Regulatory assets associated with asset retirement obligations | 40 |
| | 7 |
| 38 |
| | 55 |
|
Other | 26 |
| | 22 |
| 13 |
| | 12 |
|
Total | 1,109 |
| | 968 |
| 812 |
| | 1,192 |
|
Deferred tax assets- | | | | | | |
Federal effect of state deferred taxes | 33 |
| | 31 |
| 25 |
| | 37 |
|
Postretirement benefits | 26 |
| | 18 |
| 17 |
| | 26 |
|
Pension and other employee benefits | 65 |
| | 66 |
| 49 |
| | 72 |
|
Property differences | | 98 |
| | 1 |
|
Regulatory liability associated with Tax Reform Legislation (not subject to normalization) | | 19 |
| | — |
|
Property reserve | 15 |
| | 13 |
| 10 |
| | 17 |
|
Asset retirement obligations | 40 |
| | 7 |
| 38 |
| | 55 |
|
Alternative minimum tax carryforward | 18 |
| | 18 |
| 7 |
| | 18 |
|
Other | 19 |
| | 18 |
| 12 |
| | 18 |
|
Total | 216 |
| | 171 |
| 275 |
| | 244 |
|
Accumulated deferred income taxes | $ | 893 |
| | $ | 797 |
| $ | 537 |
| | $ | 948 |
|
On November 20, 2015,The implementation of the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from prepaid expenses of $3 million to non-currentTax Reform Legislation significantly reduced accumulated deferred income taxes, in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information.
The application ofpartially offset by bonus depreciation provisions in current tax law hasthe Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014.tax-related regulatory liabilities.
At December 31, 2015,2017, tax-related regulatory assets to be recovered from customers were $61$31 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest.
At December 31, 2015,2017, the tax-related regulatory liabilities to be credited to customers were $3$458 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and unamortized ITCs.
In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to approximately $1 million annually for 2015, 2014, and 2013. At December 31, 2015, all ITCs available to reduce federal income taxes payable had been utilized.
NOTES (continued)
Gulf Power Company 2015 Annual Report
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0% | | 35.0% | | 35.0% | 35.0% | | 35.0% | | 35.0% |
State income tax, net of federal deduction | 3.9 | | 3.5 | | 3.5 | 3.7 | | 3.4 | | 3.9 |
Non-deductible book depreciation | 0.5 | | 0.4 | | 0.5 | 0.2 | | 0.6 | | 0.5 |
Differences in prior years' deferred and current tax rates | (0.1) | | (0.1) | | (0.2) | — | | (0.1) | | (0.1) |
AFUDC equity | (1.8) | | (1.8) | | (1.1) | — | | — | | (1.8) |
Other, net | (0.6) | | 0.1 | | (0.1) | 0.5 | | 0.6 | | (0.6) |
Effective income tax rate | 36.9% | | 37.1% | | 37.6% | 39.4% | | 39.5% | | 36.9% |
NOTES (continued)
Gulf Power Company 2017 Annual Report
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Unrecognized Tax Benefits
The Company has no material unrecognized tax benefits for 2015 or 2014.the periods presented. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial and the Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances, but an estimate of the range of reasonably possible outcomes cannot be determined at this time.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Securities Due Within One Year
At December 31, 2015,2017, the Company had $110no long-term debt due within one year. At December 31, 2016, the Company had $87 million of long-term debt due within one year.
Maturities from 2017 through 20202022 applicable to total long-term debt are as follows: $85 million in 2017 andinclude $175 million in 2020.2020 and $141 million in 2022. There are no scheduled maturities in 2018, 2019, or 2019.2021.
Bank Term Loans
At December 31, 2016, the Company had $100 million of bank term loans outstanding. In March 2017, the Company extended the maturity of its $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.
Senior Notes
At each of December 31, 20152017 and 20142016, the Company had a total of $1.01 billion$990 million and $1.07 billion$777 million of senior notes outstanding, respectively. These senior notes are effectively subordinate to all secured debt of the Company, which totaled approximately $41 million at both December 31, 20152017 and 2014.2016.
In September 2015,May 2017, the Company redeemed $60issued $300 million aggregate principal amount of Series L 5.65%2017A 3.30% Senior Notes due September 1, 2035.May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017, to repay outstanding commercial paper borrowings, to repay a $100 million short-term floating rate bank loan, and to redeem, in June 2017, all outstanding shares of preference stock. See "Bank Term Loans" and "Outstanding Classes of Capital Stock" herein for more information.
Pollution Control Revenue Bonds
Pollution control revenue bond obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bondsbond obligations outstanding at December 31, 20152017 and 20142016 was $309 million.
In July 2015, the Company purchased and held $13 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds (Gulf Power Company Project), Series 2012. The Company remarketed these bonds to the public on July 16, 2015.
Outstanding Classes of Capital Stock
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company's preferred stock and Class A preferred stock, without preference between classes, would rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2015.2017. The Company's preference stock rankswould rank senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. No shares of preference stock were outstanding at December 31, 2017. In June 2017, the Company redeemed 550,000 shares ($55 million
NOTES (continued)
Gulf Power Company 20152017 Annual Report
to the common stock with respect to the paymentaggregate liquidation amount) of dividends6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and voluntary or involuntary dissolution. Certain series500,000 shares ($50 million aggregate liquidation amount) of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, certain series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends.Series 2013A 5.60% Preference Stock.
In January 2015,2017, the Company issued 200,0001,750,000 shares of common stock to Southern Company and realized proceeds of $20 million.$175 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Assets Subject to Lien
The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an aggregate outstanding principal amount of $41 million as of December 31, 2015.2017. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries.
Bank Credit Arrangements
At December 31, 20152017, committed credit arrangements with banks were as follows:
| | Expires | Expires | | | | | | Executable Term-Loans | | Due Within One Year | Expires | | | | | | Executable Term Loans | | Expires Within One Year |
2016 | 2017 | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
2018 | | 2018 | | 2019 | | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
(in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) |
$ | 80 |
| $ | 30 |
| $ | 165 |
| | $ | 275 |
| | $ | 275 |
| | $ | 50 |
| | $ | — |
| | $ | 50 |
| | $ | 30 |
| 30 |
| | $ | 25 |
| | $ | 225 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 20 |
| | $ | 10 |
|
In November 2015,2017, the Company amended and restated certain$195 million of its multi-year credit arrangements which, among other things, extendedto extend the maturity dates for the majority of the Company's agreements from 20162017 and 2018 to 2018.2020.
Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company.
Subject to applicable market conditions, the Company expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of these bank credit arrangements contain covenants that limit the Company's debt level to 65% of total capitalization, as defined in the arrangements. For purposes of these definitions, debt excludes certain hybrid securities. At December 31, 2015,2017, the Company was in compliance with these covenants.
Most of the $275$280 million of unused credit arrangements with banks provide liquidity support to the Company's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 20152017 was approximately $82 million. In addition, at December 31, 2015,2017, the Company had $33$75 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
For short-term cash needs, the Company borrows primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank loans are included in notes payable inon the balance sheets.
NOTES (continued)
Gulf Power Company 20152017 Annual Report
Details of short-term borrowings were as follows:
|
| | | | | |
| Commercial Paper at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2015 | $ | 142 |
| | 0.7% |
December 31, 2014 | $ | 110 |
| | 0.3% |
|
| | | | | |
| Short-term Debt at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2017: | | | |
Commercial paper | $ | 45 |
| | 2.0% |
December 31, 2016: | | | |
Commercial paper | $ | 168 |
| | 1.1% |
Short-term bank debt | 100 |
| | 1.5% |
Total | $ | 268 |
| | 1.2% |
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2015, 2014,2017, 2016, and 2013,2015, the Company incurred fuel expense of $445$427 million, $605$432 million, and $533$445 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under purchased power agreementsa PPA accounted for as an operating leaseslease was $75 million $50 million,each year for 2017, 2016, and $21 million for 2015, 2014, and 2013, respectively.2015.
Estimated total minimum long-term commitments at December 31, 20152017 were as follows:
| | | Operating Lease PPAs | Operating Lease PPA |
| (in millions) | (in millions) |
2016 | $ | 79 |
| |
2017 | 79 |
| |
2018 | 79 |
| $ | 79 |
|
2019 | 79 |
| 79 |
|
2020 | 79 |
| 79 |
|
2021 and thereafter | 191 |
| |
2021 | | 79 |
|
2022 | | 79 |
|
2023 and thereafter | | 33 |
|
Total | $ | 586 |
| $ | 428 |
|
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Operating Leases
In addition to the operating lease PPAsPPA discussed above, the Company has entered into operating leases with Southern Linc and other third parties for the use of cellular tower space. These agreements have initial terms ranging from five to 10 years and renewal options of up to five years. The Company also has other operating lease agreements with various terms and expiration dates. Total rent expense waslease payments were $10 million, $9 million, and $14 million $15 million,for 2017, 2016, and$18 million for 2015, 2014,respectively. The Company includes any step rents, fixed escalations, and 2013, respectively.
Estimated totalreasonably assured renewal periods in its computation of minimum lease payments under these operating leases at December 31, 2015 were as follows:payments.
NOTES (continued)
Gulf Power Company 20152017 Annual Report
Estimated total minimum lease payments under these operating leases at December 31, 2017 were as follows:
| | | Minimum Lease Payments | Minimum Lease Payments |
| Barges & Railcars | | Other | | Total | Affiliate Operating Leases(a) | | Non-Affiliate Operating Leases(b) | | Total |
| (in millions) | (in millions) |
2016 | $ | 9 |
| | $ | 1 |
| | $ | 10 |
| |
2017 | 6 |
| | 1 |
| | 7 |
| |
2018 | 4 |
| | — |
| | 4 |
| $ | 2 |
| | $ | 7 |
| | $ | 9 |
|
2019 | | 1 |
| | 1 |
| | 2 |
|
2020 | | 1 |
| | 1 |
| | 2 |
|
2021 | | 1 |
| | — |
| | 1 |
|
2022 | | 1 |
| | — |
| | 1 |
|
2023 and thereafter | | 4 |
| | 1 |
| | 5 |
|
Total | $ | 19 |
| | $ | 2 |
| | $ | 21 |
| $ | 10 |
| | $ | 10 |
| | $ | 20 |
|
| |
(a) | Includes operating leases for cellular tower space. |
| |
(b) | Includes operating leases for barges, facilities, and other equipment. |
The Company and Mississippi Power jointly entered into an operating lease agreement for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of the lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options. The Company's share of the lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, was $2 million in 2015, and $3 million in both 2014 and 2013. The Company's annual railcar lease payments for 2016 and 2017 will average approximately $1 million each year. There are no lease payment obligations for the period 2018 and thereafter.
In addition to railcar leases, the Company has operating lease agreements for railcars, barges, and towboats for the transport of coal to Plants Crist and Smith.coal. The Company has the option to renew the leases at the end of the lease term. The Company's lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, were $7 million in 2017, $5 million in 2016, and $10 million in both 2015 and 2014 and $12 million in 2013.2015. The Company's annual barge and towboat payments for 2016 through 2018 will averageare expected to be approximately $5$6 million each year..
8. STOCK COMPENSATION
Stock-Based Compensation
Stock-based compensation primarily in the form of Southern Company stock optionsperformance share units and performance sharerestricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2015,2017, there were 198168 current and former employees participating in the stock option, and performance share unit, programs.
Stock Options
Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualifiedand restricted stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units.
For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 432,371 shares and 285,209 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93, respectively.
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $2 million, $5 million, and $2 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million, $2 million, and $1 million for the years ended December 31, 2015, 2014, and 2013, respectively. As
NOTES (continued)
Gulf Power Company 2015 Annual Report
of December 31, 2015, the aggregate intrinsic value for the options outstanding and options exercisable was $7 million and $5 million, respectively.unit programs.
Performance Share Units
From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period which equates to the requisite service period for accounting purposes.period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
The performance goal for allSouthern Company issues performance share units issued from 2010 through 2014 waswith performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For thesepeers, performance share units at the end of three years, active employees receive shareswith performance goals based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service duringcumulative earnings per share (EPS) over the performance period, prior to retirement. and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
Beginning in 2015, Southern
NOTES (continued)
Gulf Power Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. 2017 Annual Report
The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. TheEmployees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement of the employee.retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, employees of the Company were granted performance share units of 48,962, 37,829,28,423, 57,333, and 30,627,48,962, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014,2017, 2016, and 2013,2015, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $46.38, $37.54,$47.30, $45.18, and $40.50,$46.38, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $47.75.$49.18, $48.83, and $47.75, respectively.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, total compensation cost for performance share units recognized in income was $2 million, $1 million, and $1 million, respectively. Thethe related tax benefit also recognized in income was $1 million in 2015 and immaterial in 2014 and 2013.immaterial. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees areis recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015, there was $2 million of2017, total unrecognized compensation cost related to performance share award units that will bewas immaterial.
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a weighted-averageresult, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of approximately 19 months.retirement eligibility.
For the year ended December 31, 2017, employees of the Company were granted 15,736 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $48.88.
II-353For the year ended December 31, 2017, total compensation cost and the related tax benefit for restricted stock units recognized in income was immaterial. As of December 31, 2017, total unrecognized compensation cost related to restricted stock units was immaterial.
Stock Options
In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017, all compensation cost related to stock option awards has been recognized.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $2 million, $3 million, and $2 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises were immaterial for all years presented. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016,
NOTES (continued)
Gulf Power Company 20152017 Annual Report
all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017, the aggregate intrinsic value for the options outstanding and exercisable was $3 million.
9. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
As of December 31, 20152017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Interest rate derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| |
Cash equivalents | 18 |
| | — |
| | — |
| | 18 |
| $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
Total | $ | 18 |
| | $ | 1 |
| | $ | — |
| | $ | 19 |
| |
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 100 |
| | $ | — |
| | $ | 100 |
| $ | — |
| | $ | 21 |
| | $ | — |
| | $ | 21 |
|
As of December 31, 20142016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
|
Cash equivalents | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| 20 |
| | — |
| | — |
| | 20 |
|
Total | | $ | 20 |
| | $ | 5 |
| | $ | — |
| | $ | 25 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 72 |
| | $ | — |
| | $ | 72 |
| $ | — |
| | $ | 29 |
| | $ | — |
| | $ | 29 |
|
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter
NOTES (continued)
Gulf Power Company 2017 Annual Report
products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market’smarket's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms,
NOTES (continued)
Gulf Power Company 2015 Annual Report
counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 10 for additional information on how these derivatives are used.
As of December 31, 20152017 and 20142016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt: | | | |
2015 | $ | 1,303 |
| | $ | 1,339 |
|
2014 | $ | 1,362 |
| | $ | 1,477 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt: | | | |
2017 | $ | 1,285 |
| | $ | 1,334 |
|
2016 | $ | 1,074 |
| | $ | 1,097 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.
10. DERIVATIVES
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a stipulation and agreement that prospectively imposed a moratorium on the Company's fuel-hedging program in October 2016 through December 31, 2017. In connection with the 2017 Rate Case Settlement Agreement, the Florida PSC extended the moratorium on the Company's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.
Energy-related derivative contracts are accounted for under one of twothree methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
NOTES (continued)
Gulf Power Company 2017 Annual Report
At December 31, 20152017, the net volume of energy-related derivative contracts for natural gas positions totaled 8222 million mmBtu for the Company, with the longest hedge date of 2020 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions.
In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 3 million mmBtu for the Company.
Interest Rate Derivatives
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions
NOTES (continued)
Gulf Power Company 2015 Annual Report
affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings.
At December 31, 2015, the following2017, there were no interest rate derivative was outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2015 |
| (in millions) | | | | | | | | (in millions) |
Cash Flow Hedges of Forecasted Debt | | | | | | | | |
| $ | 80 |
| | 3-month LIBOR | | 2.32% | | December 2026 | | $ | 1 |
|
derivatives outstanding.The estimated pre-tax losses related to interest rate derivatives that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 20162018 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2026.
Derivative Financial Statement Presentation and Amounts
At December 31, 2015 and 2014, the fair value ofThe Company enters into energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | — |
| | $ | — |
| | Liabilities from risk management activities | $ | 49 |
| | $ | 37 |
|
| Other deferred charges and assets | — |
| | — |
| | Other deferred credits and liabilities | 51 |
| | 35 |
|
Total derivatives designated as hedging instruments for regulatory purposes | | $ | — |
| | $ | — |
| | | $ | 100 |
| | $ | 72 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | |
Interest rate derivatives: | Other current assets | $ | 1 |
| | $ | — |
| | Liabilities from risk management activities | $ | — |
| | $ | — |
|
Total | | $ | 1 |
| | $ | — |
| | | $ | 100 |
| | $ | 72 |
|
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2015 and 2014.
The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contractsthat may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
At December 31, 20152017 and 2014,2016, the fair value of energy-related derivatives was reflected on the balance sheets as follows:
|
| | | | | | | | | | | | |
| 2017 | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | — |
| $ | 14 |
| $ | 4 |
| $ | 12 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 7 |
| 1 |
| 17 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | — |
| $ | 21 |
| $ | 5 |
| $ | 29 |
|
Gross amounts recognized | $ | — |
| $ | 21 |
| $ | 5 |
| $ | 29 |
|
Gross amounts offset | $ | — |
| $ | — |
| $ | (4 | ) | $ | (4 | ) |
Net amounts recognized on the Balance Sheets | $ | — |
| $ | 21 |
| $ | 1 |
| $ | 25 |
|
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2017 and interest rate derivatives presented in the tables above do not have amounts available for offset.2016.
NOTES (continued)
Gulf Power Company 20152017 Annual Report
At December 31, 20152017 and 20142016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instrumentsderivatives designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
| | | Unrealized Losses | | Unrealized Gains | Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 | Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (49 | ) | | $ | (37 | ) | | Other regulatory liabilities, current | $ | — |
| | $ | — |
| |
Energy-related derivatives:(*) | | Other regulatory assets, current | $ | (14 | ) | | $ | (9 | ) | | Other regulatory liabilities, current | $ | — |
| | $ | 1 |
|
| Other regulatory assets, deferred | (51 | ) | | (35 | ) | | Other regulatory liabilities, deferred | — |
| | — |
| Other regulatory assets, deferred | (7 | ) | | (16 | ) | | Other regulatory liabilities, deferred | — |
| | — |
|
Total energy-related derivative gains (losses) | | $ | (100 | ) | | $ | (72 | ) | | $ | — |
| | $ | — |
| | $ | (21 | ) | | $ | (25 | ) | | $ | — |
| | $ | 1 |
|
| |
(*) | The unrealized gains and losses for derivative contracts subject to netting arrangements were presented net on the balance sheets. |
For the years ended December 31, 20152017, 20142016, and 20132015, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
(Effective Portion) | | | Amount |
Derivative Category | 2015 | | 2014 | | 2013 | | Statements of Income Location | 2015 | | 2014 | | 2013 |
| (in millions) | | | (in millions) |
Interest rate derivatives | $ | 1 |
| | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | | $ | (1 | ) |
Thereimmaterial and there was no material ineffectiveness recorded in earnings for any period presented.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were not material.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015,2017, the Company'sCompany had no collateral posted with its derivative counterparties was not material.to satisfy these arrangements.
At December 31, 2015,2017, the fair value of derivative liabilities with contingent features was $22 million.immaterial. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-relatedcredit-risk related contingent features, at a rating below BBB- and/orand /or Baa3, were $52$12 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES (continued)
Gulf Power Company 20152017 Annual Report
11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preference Stock |
| (in millions) |
March 2015 | $ | 357 |
| | $ | 72 |
| | $ | 37 |
|
June 2015 | 384 |
| | 69 |
| | 35 |
|
September 2015 | 429 |
| | 91 |
| | 48 |
|
December 2015 | 313 |
| | 58 |
| | 28 |
|
| | | | | |
March 2014 | $ | 407 |
| | $ | 74 |
| | $ | 37 |
|
June 2014 | 384 |
| | 69 |
| | 34 |
|
September 2014 | 438 |
| | 88 |
| | 46 |
|
December 2014 | 361 |
| | 50 |
| | 23 |
|
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income After Dividends on Preference Stock |
| (in millions) |
March 2017 | $ | 350 |
| | $ | 46 |
| | $ | 18 |
|
June 2017 | 357 |
| | 75 |
| | 35 |
|
September 2017 | 437 |
| | 115 |
| | 63 |
|
December 2017 | 372 |
| | 53 |
| | 19 |
|
| | | | | |
March 2016 | $ | 335 |
| | $ | 65 |
| | $ | 29 |
|
June 2016 | 365 |
| | 74 |
| | 34 |
|
September 2016 | 436 |
| | 90 |
| | 45 |
|
December 2016 | 349 |
| | 54 |
| | 23 |
|
The Company's business is influenced by seasonal weather conditions.
SELECTED FINANCIAL AND OPERATING DATA 2011-20152013-2017
Gulf Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions) | $ | 1,483 |
| | $ | 1,590 |
| | $ | 1,440 |
| | $ | 1,440 |
| | $ | 1,520 |
| $ | 1,516 |
| | $ | 1,485 |
| | $ | 1,483 |
| | $ | 1,590 |
| | $ | 1,440 |
|
Net Income After Dividends on Preference Stock (in millions) | $ | 148 |
| | $ | 140 |
| | $ | 124 |
| | $ | 126 |
| | $ | 105 |
| $ | 135 |
| | $ | 131 |
| | $ | 148 |
| | $ | 140 |
| | $ | 124 |
|
Cash Dividends on Common Stock (in millions) | $ | 130 |
| | $ | 123 |
| | $ | 115 |
| | $ | 116 |
| | $ | 110 |
| $ | 165 |
| | $ | 120 |
| | $ | 130 |
| | $ | 123 |
| | $ | 115 |
|
Return on Average Common Equity (percent) | 11.11 |
| | 11.02 |
| | 10.30 |
| | 10.92 |
| | 9.55 |
| 9.22 |
| | 9.52 |
| | 11.11 |
| | 11.02 |
| | 10.30 |
|
Total Assets (in millions)(a)(b) | $ | 4,920 |
| | $ | 4,697 |
| | $ | 4,321 |
| | $ | 4,167 |
| | $ | 3,858 |
| $ | 4,797 |
| | $ | 4,822 |
| | $ | 4,920 |
| | $ | 4,697 |
| | $ | 4,321 |
|
Gross Property Additions (in millions) | $ | 247 |
| | $ | 361 |
| | $ | 305 |
| | $ | 325 |
| | $ | 338 |
| $ | 201 |
| | $ | 179 |
| | $ | 247 |
| | $ | 361 |
| | $ | 305 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 1,355 |
| | $ | 1,309 |
| | $ | 1,235 |
| | $ | 1,181 |
| | $ | 1,125 |
| $ | 1,531 |
| | $ | 1,389 |
| | $ | 1,355 |
| | $ | 1,309 |
| | $ | 1,235 |
|
Preference stock | 147 |
| | 147 |
| | 147 |
| | 98 |
| | 98 |
| — |
| | 147 |
| | 147 |
| | 147 |
| | 147 |
|
Long-term debt(a) | 1,193 |
| | 1,362 |
| | 1,150 |
| | 1,178 |
| | 1,226 |
| 1,285 |
| | 987 |
| | 1,193 |
| | 1,362 |
| | 1,150 |
|
Total (excluding amounts due within one year) | $ | 2,695 |
| | $ | 2,818 |
| | $ | 2,532 |
| | $ | 2,457 |
| | $ | 2,449 |
| $ | 2,816 |
| | $ | 2,523 |
| | $ | 2,695 |
| | $ | 2,818 |
| | $ | 2,532 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 50.3 |
| | 46.5 |
| | 48.8 |
| | 48.1 |
| | 45.9 |
| 54.4 |
| | 55.1 |
| | 50.3 |
| | 46.5 |
| | 48.8 |
|
Preference stock | 5.4 |
| | 5.2 |
| | 5.8 |
| | 4.0 |
| | 4.0 |
| — |
| | 5.8 |
| | 5.4 |
| | 5.2 |
| | 5.8 |
|
Long-term debt(a) | 44.3 |
| | 48.3 |
| | 45.4 |
| | 47.9 |
| | 50.1 |
| 45.6 |
| | 39.1 |
| | 44.3 |
| | 48.3 |
| | 45.4 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Customers (year-end): | | | | | | | | | | | | | | | | | | |
Residential | 393,149 |
| | 388,292 |
| | 383,980 |
| | 379,922 |
| | 378,248 |
| 404,273 |
| | 398,501 |
| | 393,149 |
| | 388,292 |
| | 383,980 |
|
Commercial | 55,460 |
| | 54,892 |
| | 54,567 |
| | 53,808 |
| | 53,450 |
| 56,700 |
| | 56,091 |
| | 55,460 |
| | 54,892 |
| | 54,567 |
|
Industrial | 248 |
| | 260 |
| | 260 |
| | 264 |
| | 273 |
| 255 |
| | 254 |
| | 248 |
| | 260 |
| | 260 |
|
Other | 614 |
| | 603 |
| | 582 |
| | 577 |
| | 565 |
| 578 |
| | 569 |
| | 614 |
| | 603 |
| | 582 |
|
Total | 449,471 |
| | 444,047 |
| | 439,389 |
| | 434,571 |
| | 432,536 |
| 461,806 |
| | 455,415 |
| | 449,471 |
| | 444,047 |
| | 439,389 |
|
Employees (year-end) | 1,391 |
| | 1,384 |
| | 1,410 |
| | 1,416 |
| | 1,424 |
| 1,288 |
| | 1,352 |
| | 1,391 |
| | 1,384 |
| | 1,410 |
|
|
| |
(a) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $8 million $8 million, $8 million, and $9$8 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b) | A reclassification of deferred tax assets from Total Assets of $3 million $8 million, $2 million, and $5$8 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-17. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
SELECTED FINANCIAL AND OPERATING DATA 2013-2017 (continued)
Gulf Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 720 |
| | $ | 714 |
| | $ | 698 |
| | $ | 700 |
| | $ | 632 |
|
Commercial | 412 |
| | 410 |
| | 403 |
| | 408 |
| | 395 |
|
Industrial | 144 |
| | 152 |
| | 144 |
| | 153 |
| | 139 |
|
Other | 5 |
| | 5 |
| | 4 |
| | 6 |
| | 4 |
|
Total retail | 1,281 |
| | 1,281 |
| | 1,249 |
| | 1,267 |
| | 1,170 |
|
Wholesale — non-affiliates | 57 |
| | 61 |
| | 107 |
| | 129 |
| | 109 |
|
Wholesale — affiliates | 108 |
| | 75 |
| | 58 |
| | 130 |
| | 100 |
|
Total revenues from sales of electricity | 1,446 |
| | 1,417 |
| | 1,414 |
| | 1,526 |
| | 1,379 |
|
Other revenues | 70 |
| | 68 |
| | 69 |
| | 64 |
| | 61 |
|
Total | $ | 1,516 |
| | $ | 1,485 |
| | $ | 1,483 |
| | $ | 1,590 |
| | $ | 1,440 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 5,229 |
| | 5,358 |
| | 5,365 |
| | 5,362 |
| | 5,089 |
|
Commercial | 3,814 |
| | 3,869 |
| | 3,898 |
| | 3,838 |
| | 3,810 |
|
Industrial | 1,740 |
| | 1,830 |
| | 1,798 |
| | 1,849 |
| | 1,700 |
|
Other | 26 |
| | 25 |
| | 25 |
| | 26 |
| | 21 |
|
Total retail | 10,809 |
| | 11,082 |
| | 11,086 |
| | 11,075 |
| | 10,620 |
|
Wholesale — non-affiliates | 749 |
| | 751 |
| | 1,040 |
| | 1,670 |
| | 1,163 |
|
Wholesale — affiliates | 3,887 |
| | 2,784 |
| | 1,906 |
| | 3,284 |
| | 3,127 |
|
Total | 15,445 |
| | 14,617 |
| | 14,032 |
| | 16,029 |
| | 14,910 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 13.77 |
| | 13.33 |
| | 13.01 |
| | 13.06 |
| | 12.43 |
|
Commercial | 10.80 |
| | 10.60 |
| | 10.34 |
| | 10.64 |
| | 10.37 |
|
Industrial | 8.28 |
| | 8.31 |
| | 8.01 |
| | 8.28 |
| | 8.15 |
|
Total retail | 11.85 |
| | 11.56 |
| | 11.27 |
| | 11.44 |
| | 11.02 |
|
Wholesale | 3.56 |
| | 3.85 |
| | 5.60 |
| | 5.23 |
| | 4.87 |
|
Total sales | 9.36 |
| | 9.69 |
| | 10.08 |
| | 9.52 |
| | 9.25 |
|
Residential Average Annual | | | | | | | | | |
Kilowatt-Hour Use Per Customer | 13,015 |
| | 13,515 |
| | 13,705 |
| | 13,865 |
| | 13,301 |
|
Residential Average Annual | | | | | | | | | |
Revenue Per Customer | $ | 1,792 |
| | $ | 1,801 |
| | $ | 1,783 |
| | $ | 1,811 |
| | $ | 1,653 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 2,278 |
| | 2,278 |
| | 2,583 |
| | 2,663 |
| | 2,663 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 2,202 |
| | 2,033 |
| | 2,488 |
| | 2,684 |
| | 1,729 |
|
Summer | 2,422 |
| | 2,503 |
| | 2,491 |
| | 2,424 |
| | 2,356 |
|
Annual Load Factor (percent) | 55.2 |
| | 54.7 |
| | 54.9 |
| | 51.1 |
| | 55.9 |
|
Plant Availability Fossil-Steam (percent) | 79.3 |
| | 81.0 |
| | 88.3 |
| | 89.4 |
| | 92.8 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 33.1 |
| | 31.0 |
| | 33.5 |
| | 44.5 |
| | 36.4 |
|
Gas | 27.8 |
| | 23.2 |
| | 25.6 |
| | 22.2 |
| | 23.0 |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 35.6 |
| | 41.1 |
| | 30.4 |
| | 28.9 |
| | 37.0 |
|
From affiliates | 3.5 |
| | 4.7 |
| | 10.5 |
| | 4.4 |
| | 3.6 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
SELECTED FINANCIAL AND OPERATING DATA 2011-2015 (continued)
Gulf Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
|
Operating Revenues (in millions): | | | | | | | | | |
Residential | $ | 698 |
| | $ | 700 |
| | $ | 632 |
| | $ | 609 |
| | $ | 637 |
|
Commercial | 403 |
| | 408 |
| | 395 |
| | 390 |
| | 408 |
|
Industrial | 144 |
| | 153 |
| | 139 |
| | 140 |
| | 158 |
|
Other | 4 |
| | 6 |
| | 4 |
| | 5 |
| | 5 |
|
Total retail | 1,249 |
| | 1,267 |
| | 1,170 |
| | 1,144 |
| | 1,208 |
|
Wholesale — non-affiliates | 107 |
| | 129 |
| | 109 |
| | 107 |
| | 134 |
|
Wholesale — affiliates | 58 |
| | 130 |
| | 100 |
| | 124 |
| | 111 |
|
Total revenues from sales of electricity | 1,414 |
| | 1,526 |
| | 1,379 |
| | 1,375 |
| | 1,453 |
|
Other revenues | 69 |
| | 64 |
| | 61 |
| | 65 |
| | 67 |
|
Total | $ | 1,483 |
| | $ | 1,590 |
| | $ | 1,440 |
| | $ | 1,440 |
| | $ | 1,520 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | |
Residential | 5,365 |
| | 5,362 |
| | 5,089 |
| | 5,054 |
| | 5,305 |
|
Commercial | 3,898 |
| | 3,838 |
| | 3,810 |
| | 3,859 |
| | 3,911 |
|
Industrial | 1,798 |
| | 1,849 |
| | 1,700 |
| | 1,725 |
| | 1,799 |
|
Other | 25 |
| | 26 |
| | 21 |
| | 25 |
| | 25 |
|
Total retail | 11,086 |
| | 11,075 |
| | 10,620 |
| | 10,663 |
| | 11,040 |
|
Wholesale — non-affiliates | 1,040 |
| | 1,670 |
| | 1,163 |
| | 977 |
| | 2,013 |
|
Wholesale — affiliates | 1,906 |
| | 3,284 |
| | 3,127 |
| | 4,370 |
| | 2,608 |
|
Total | 14,032 |
| | 16,029 |
| | 14,910 |
| | 16,010 |
| | 15,661 |
|
Average Revenue Per Kilowatt-Hour (cents): | | | | | | | | | |
Residential | 13.01 |
| | 13.06 |
| | 12.43 |
| | 12.06 |
| | 12.01 |
|
Commercial | 10.34 |
| | 10.64 |
| | 10.37 |
| | 10.11 |
| | 10.44 |
|
Industrial | 8.01 |
| | 8.28 |
| | 8.15 |
| | 8.14 |
| | 8.80 |
|
Total retail | 11.27 |
| | 11.44 |
| | 11.02 |
| | 10.73 |
| | 10.95 |
|
Wholesale | 5.60 |
| | 5.23 |
| | 4.87 |
| | 4.31 |
| | 5.30 |
|
Total sales | 10.08 |
| | 9.52 |
| | 9.25 |
| | 8.59 |
| | 9.28 |
|
Residential Average Annual | | | | | | | | | |
Kilowatt-Hour Use Per Customer | 13,705 |
| | 13,865 |
| | 13,301 |
| | 13,303 |
| | 14,028 |
|
Residential Average Annual | | | | | | | | | |
Revenue Per Customer | $ | 1,783 |
| | $ | 1,811 |
| | $ | 1,653 |
| | $ | 1,604 |
| | $ | 1,685 |
|
Plant Nameplate Capacity | | | | | | | | | |
Ratings (year-end) (megawatts) | 2,583 |
| | 2,663 |
| | 2,663 |
| | 2,663 |
| | 2,663 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | |
Winter | 2,488 |
| | 2,684 |
| | 1,729 |
| | 2,130 |
| | 2,485 |
|
Summer | 2,491 |
| | 2,424 |
| | 2,356 |
| | 2,344 |
| | 2,527 |
|
Annual Load Factor (percent) | 54.9 |
| | 51.1 |
| | 55.9 |
| | 56.3 |
| | 54.5 |
|
Plant Availability Fossil-Steam (percent)* | 88.3 |
| | 89.4 |
| | 92.8 |
| | 82.5 |
| | 84.7 |
|
Source of Energy Supply (percent): | | | | | | | | | |
Coal | 33.5 |
| | 44.5 |
| | 36.4 |
| | 34.6 |
| | 49.4 |
|
Gas | 25.6 |
| | 22.2 |
| | 23.0 |
| | 23.5 |
| | 24.0 |
|
Purchased power — | | | | | | | | | |
From non-affiliates | 30.4 |
| | 28.9 |
| | 37.0 |
| | 40.2 |
| | 22.3 |
|
From affiliates | 10.5 |
| | 4.4 |
| | 3.6 |
| | 1.7 |
| | 4.3 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
|
| |
* | Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
MISSISSIPPI POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Mississippi Power Company 20152017 Annual Report
The management of Mississippi Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2015.2017.
/s/ Anthony L. Wilson
Anthony L. Wilson
Chairman, President, and Chief Executive Officer
/s/ Moses H. Feagin
Moses H. Feagin
Vice President, Chief Financial Officer, and Treasurer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of
Mississippi Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets and statements of capitalization of Mississippi Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014, and2016, the related statements of operations, comprehensive income (loss), common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2015. 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-431 to II-477) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements based on our audits.
We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements (pages II-399 to II-445) present fairly, in all material respects, the financial position of Mississippi Power Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing acquisition, construction, and operation of the Kemper IGCCCounty energy facility |
AFUDC | Allowance for funds used during construction |
Alabama Power | Alabama Power Company |
APAARO | Asset purchase agreementretirement obligation |
ASC | Accounting Standards Codification |
Baseload ActASU | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of MississippiAccounting Standards Update |
CCR | Coal combustion residuals |
Clean Air Act | Clean Air Act Amendments of 1990 |
CO2 | Carbon dioxide |
Cooperative Energy | Electric cooperative in Mississippi |
CPCN | Certificate of public convenience and necessity |
CWIP | Construction work in progress |
DOE | U.S. Department of Energy |
ECM | Energy cost management clause |
ECO | Environmental compliance overview |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IGCC | Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe) |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
Kemper IGCC | IGCC facility under construction in Kemper County, Mississippi |
KWH | Kilowatt-hour |
LIBOR | London Interbank Offered Rate |
Mirror CWIP | A regulatory liability account for use in mitigating future rate impacts forused by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility, which were subsequently refunded to customers |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MPUS | Mississippi Public Utilities Staff |
MRA | Municipal and Rural Associations |
MW | Megawatt |
NOX | Nitrogen oxide |
OCI | Other comprehensive income |
PEP | Performance evaluation plan |
Plant Daniel Units 3 and 4 | Combined cycle Units 3 and 4 at Plant Daniel |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company(excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
PPA | Power purchase agreement |
PSC | Public Service Commission |
ROE | Return on equity |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
scrubber | Flue gas desulfurization system |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SMEPASO2 | South Mississippi Electric Power AssociationSulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
SRR | System Restoration Rider, a tariff for retail property damage reserve |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power Company |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power Company 20152017 Annual Report
OVERVIEW
Business Activities
Mississippi Power Company (the Company) operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the Company's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of major construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital and operations and maintenance expenditures required for maintenance.and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of theThe Kemper IGCC. The certificated cost estimate of the Kemper IGCC establishedCounty energy facility was approved by the Mississippi PSC was $2.4 billion withas an IGCC facility in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE(Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).
The Company placed the combined cycle and the associated common facilities portions of the Kemper County energy facility were placed in service in August 2014. In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), authorizing rates that provided for the recovery of approximately $126 million annually related to the assets previously placed in service.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket).
On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC in-service in August 2014 and continuesCounty energy facility, given the uncertainty as to focus on completingits future. At the remaindertime of project suspension, the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the third quarter 2016.
The Company's currenttotal cost estimate for the Kemper IGCC in total isCounty energy facility was approximately $6.63$7.38 billion, which includesincluding approximately $5.29$5.95 billion of costs subject to the construction cost cap. The Company does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, and was net of the $137 million in additional grants from the DOE Grants and excluding the Cost Cap Exceptions. The Company has recorded pre-tax charges to income for revisions to the cost estimate of $365 million ($226 million after tax), $868 million ($536 million after tax), and $1.1 billion ($681 million after tax) in 2015, 2014, and 2013, respectively. Since 2012, inreceived on April 8, 2016 (Additional DOE Grants). In the aggregate, the Company hashad incurred charges of $2.41$3.07 billion ($1.51.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through DecemberMay 31, 2015. The current cost estimate includes costs through August 31, 2016.
During 2015, events related to the Kemper IGCC had a significant adverse impact on the Company’s financial condition. These events include (i) the termination by SMEPA in May 2015 of the APA between the Company and SMEPA, whereby SMEPA previously agreed to purchase a 15% undivided interest in the Kemper IGCC, and the Company's subsequent return of approximately $301 million, including interest, to SMEPA; (ii) the termination of Mirror CWIP rates in July 2015 and the refund of $371 million in Mirror CWIP rate collections, including carrying costs, in the fourth quarter 2015 as a result of the Mississippi Supreme Court's (Court) reversal of2017. Given the Mississippi PSC's 2013stated intent regarding no further rate order authorizing the collection of $156 million annually in Mirror CWIP rates; and (iii) the required recapture in December 2015 of $235 million of Internal Revenue Code of 1986, as amended (Internal Revenue Code), Section 48A (Phase II) tax credits as a result of the extension of the expected in-service dateincrease for the Kemper IGCC. As a resultCounty energy facility and the subsequent suspension, cost recovery of the terminationgasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the Mirror CWIP rates, the Company submitted a filing toplant and lignite mine.
On February 6, 2018, the Mississippi PSC requesting interim ratesvoted to collect approximately $159 million annually untilapprove a final rate decision could be made on the Company's request to recover costs associated with Kemper IGCC assets that had been placed in service. The Mississippi PSC approved the implementation of the requested interim rates in August 2015. Subsequently, on December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (the 2015 Stipulation) between the Company and the MPUS, authorizing the Company to replace the interim rates with rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. Further proceedingssettlement agreement related to cost recovery for the Kemper IGCC are expectedCounty energy facility among the Company, the MPUS, and certain intervenors (Kemper Settlement Agreement). The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6%, excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the remainderKemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper IGCC is placedCounty energy facility in service which is currently expected in2018 or at any future date. On February 12, 2018, the Company made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) the Company to file a reserve margin plan with the Mississippi PSC by August 2018.
During the third quarter 2016. On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a noticeand fourth quarters of appeal2017, the Company recorded charges to income of the In-Service Asset Rate Order with the Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company’s results of operations, financial condition,$242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and liquidity. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.gasifier-related costs, and certain termination costs during
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Total pre-tax charges to income related to the Kemper County energy facility were $3.4 billion ($2.4 billion after tax) for the year ended December 31, 2017. In the aggregate, since the Kemper County energy facility project started, the Company has incurred charges of $6.2 billion ($4.1 billion after tax) through December 31, 2017.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
For additional information, see FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and "Other Matters" herein.
The Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company. For additional information, see Note 6 to the financial statements under "Going Concern." In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay $591 million of the outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
As of December 31, 2015,2017, the Company's current liabilities exceeded current assets by approximately $1.3 billion$911 million primarily due to a $900 million of bankunsecured term loans scheduled to matureloan that matures on April 1, 2016, and $300 million in senior notes scheduled to mature on October 15, 2016. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein and Note 6 to the financial statements for additional information.March 31, 2018. The Company expects to refinance its 2016 debt maturitiesthe unsecured term loan with bank term loans. Theexternal security issuances and/or borrowings from financial institutions or Southern Company. To fund the Company's capital needs over the next 12 months, the Company intends to utilize operating cash flows, andexternal security issuances, lines of credit, (to the extent available) as well asbank term loans, and, under certain circumstances, equity contributions from Southern Company, and, to fund the remainder of the Company's capital needs.
Key Performance Indicatorsextent necessary, loans from Southern Company.
The Company continues to focus on several key performance indicators, including the construction and start-up of the Kemper IGCC, to measure the Company's performance for customers and employees.
indicators. In recognition that the Company's long-term financial success is dependent upon how well it satisfies its customers' needs, the Company's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to the Company's allowed return.ROE. PEP measures the Company's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in percentage of time customers had electric service (40%); and customer satisfaction, measured in a survey of residential customers (20%). The Company also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
On January 16, 2018, the Mississippi PSC approved the 2018 retail fuel cost recovery factor, effective February 2018 through January 2019, which resulted in a $39 million increase in annual revenues. On February 7, 2018, the Company filed its 2018 PEP forecast, requesting an increase in annual base revenues of $26 million. On February 14, 2018, the Company submitted its 2018 ECO filing, requesting an increase in annual retail revenue of $17 million. The PEP and ECO filings include the effects of Tax Reform Legislation. Rulings from the Mississippi PSC on the PEP and ECO filings are expected in the first half of 2018. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 3 to the financial statements under "Retail Regulatory Matters – Performance Evaluation Plan" for more information on PEP.
In addition to the PEP performance indicators, the Company focuses on other performance measures, including broader measuresinformation. The ultimate outcome of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.this matter cannot be determined at this time.
The Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate the Company's results and generally targets the top quartile in measuring performance, which the Company achieved during 2015.top-quartile performance.
Peak season equivalent forced outage rate (Peak Season EFOR) is an indicator of fossil plant availability and efficient generation fleet operations during the months when generation needs are greatest. The rate is calculated by dividing the number of hours of forced outages by total generation hours. The Company's 2015 fossil Peak Season EFOR of 0.76% was better than the target. Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on historical performance. The Company's 2015 performance was better than the target for these transmission and distribution reliability measures.
The Company uses net income (loss) after dividends on preferred stock as the primary measure of the Company's financial performance. See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Earnings
The Company's net loss after dividends on preferred stock was $8 million$2.59 billion in 20152017 compared to $329a $50 million net loss in 2014.2016. The change in 20152017 was primarily the result of lowerhigher pre-tax charges of $365 million$3.36 billion ($226 million2.39 billion after tax) in 20152017 compared to pre-tax charges of $868$428 million ($536264 million after tax) in 20142016 for revisions of estimated costs expected to be incurredlosses on the Company's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The reduction in net loss was also related to an increase in retail base revenues, due to the implementation of rates for certain Kemper assets placed in service that became effective with the first billing cycle in September (on August 19), and a decrease in interest expense primarily due to the termination of SMEPA's agreement to purchase a portion of the Kemper IGCC, partially offset by increases in income taxes due to a reduced net loss. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.
The Company's net loss after dividends on preferred stock was $329$50 million in 20142016 compared to $477$8 million in 2013.2015. The decreased net losschange in 20142016 was primarily the result of lowerhigher pre-tax charges of $868$428 million ($536264 million after tax) in 20142016 compared to pre-tax charges of $1.1 billion$365 million ($681226 million after tax) in 20132015 for revisions of estimated costs expected to be incurredlosses on the Company’s construction of the Kemper IGCC above the $2.88 billion cost cap establishedIGCC. The decrease in net income was partially offset by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The change was also due to wholesale base rate increases, effective in April 2013 and May 2014, and an increase in AFUDC equity primarily relatedretail revenues due to the constructionimplementation of therates in September 2015 for certain Kemper IGCC. These changes were partially offset by a decrease in retail revenues primarily as a result of the 2015 Court decision which required the reversal of revenues recorded in 2013, increases in non-fuel operations and maintenance expenses and interest expense. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
County energy facility in-service assets, partially offset by a decrease in wholesale revenues. The increase in revenues was partially offset by an increase in interest expense in 2016 compared to 2015 due to the termination of an asset purchase agreement between the Company and Cooperative Energy in 2015 and an increase in operations and maintenance expenses.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
RESULTS OF OPERATIONS
A condensed statement of operations follows:
| | | Amount | | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Operating revenues | $ | 1,138 |
| | $ | (105 | ) | | $ | 98 |
| $ | 1,187 |
| | $ | 24 |
| | $ | 25 |
|
Fuel | 443 |
| | (131 | ) | | 83 |
| 395 |
| | 52 |
| | (100 | ) |
Purchased power | 12 |
| | (31 | ) | | (6 | ) | 25 |
| | (9 | ) | | 22 |
|
Other operations and maintenance | 274 |
| | 3 |
| | 18 |
| 282 |
| | (30 | ) | | 38 |
|
Depreciation and amortization | 123 |
| | 26 |
| | 6 |
| 161 |
| | 29 |
| | 9 |
|
Taxes other than income taxes | 94 |
| | 15 |
| | (2 | ) | 104 |
| | (5 | ) | | 15 |
|
Estimated loss on Kemper IGCC | 365 |
| | (503 | ) | | (234 | ) | 3,362 |
| | 2,934 |
| | 63 |
|
Total operating expenses | 1,311 |
| | (621 | ) | | (135 | ) | 4,329 |
| | 2,971 |
| | 47 |
|
Operating income | (173 | ) | | 516 |
| | 233 |
| |
Operating loss | | (3,142 | ) | | (2,947 | ) | | (22 | ) |
Allowance for equity funds used during construction | 110 |
| | (26 | ) | | 14 |
| 72 |
| | (52 | ) | | 14 |
|
Interest expense, net of amounts capitalized | 7 |
| | (38 | ) | | 9 |
| 42 |
| | (32 | ) | | 67 |
|
Other income (expense), net | (8 | ) | | 6 |
| | (7 | ) | (8 | ) | | (1 | ) | | 1 |
|
Income taxes (benefit) | (72 | ) | | 213 |
| | 83 |
| (532 | ) | | (428 | ) | | (32 | ) |
Net income (loss) | (6 | ) | | 321 |
| | 148 |
| (2,588 | ) | | (2,540 | ) | | (42 | ) |
Dividends on preferred stock | 2 |
| | — |
| | — |
| 2 |
| | — |
| | — |
|
Net income (loss) after dividends on preferred stock | $ | (8 | ) | | $ | 321 |
| | $ | 148 |
| |
Net loss after dividends on preferred stock | | $ | (2,590 | ) | | $ | (2,540 | ) | | $ | (42 | ) |
Operating Revenues
Operating revenues for 2015 were $1.1 billion, reflecting a $105 million decrease from 2014. Details of operating revenues were as follows:
|
| | | | | | | |
| Amount |
| 2015 | | 2014 |
| (in millions) |
Retail — prior year | $ | 795 |
| | $ | 799 |
|
Estimated change resulting from — | | | |
Rates and pricing | 61 |
| | (12 | ) |
Sales growth (decline) | (3 | ) | | (1 | ) |
Weather | (1 | ) | | 3 |
|
Fuel and other cost recovery | (76 | ) | | 6 |
|
Retail — current year | 776 |
| | 795 |
|
Wholesale revenues — | | | |
Non-affiliates | 270 |
| | 323 |
|
Affiliates | 76 |
| | 107 |
|
Total wholesale revenues | 346 |
| | 430 |
|
Other operating revenues | 16 |
| | 18 |
|
Total operating revenues | $ | 1,138 |
| | $ | 1,243 |
|
Percent change | (8.4 | )% | | 8.5 | % |
Total retail revenues for 2015 decreased $19 million, or 2.4%, compared to 2014 primarily due to a lower fuel cost recovery. This decrease was partially offset by changes in rates and pricing of $61 million. Total retail revenues for 2014 decreased $5 million, or
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Operating Revenues
Operating revenues for 2017 were $1.2 billion, reflecting a $24 million increase from 2016. Details of operating revenues were as follows:
|
| | | | | | | |
| Amount |
| 2017 | | 2016 |
| (in millions) |
Retail — prior year | $ | 859 |
| | $ | 776 |
|
Estimated change resulting from — | | | |
Rates and pricing | (7 | ) | | 96 |
|
Sales growth (decline) | 4 |
| | (4 | ) |
Weather | (15 | ) | | 8 |
|
Fuel and other cost recovery | 13 |
| | (17 | ) |
Retail — current year | 854 |
| | 859 |
|
Wholesale revenues — | | | |
Non-affiliates | 259 |
| | 261 |
|
Affiliates | 56 |
| | 26 |
|
Total wholesale revenues | 315 |
| | 287 |
|
Other operating revenues | 18 |
| | 17 |
|
Total operating revenues | $ | 1,187 |
| | $ | 1,163 |
|
Percent change | 2.1 | % | | 2.2 | % |
Total retail revenues for 2017 decreased $5 million, or 0.6%, compared to 20132016 primarily due to a $15 million decrease as a result of milder weather in 2017 and the deferral of $17 million of revenue following the complete amortization of certain regulatory assets related to the Kemper County energy facility in July 2017. These decreases were partially offset by a $10 million net increase related to ECO plan rate changes in the third quarter 2016 and the second quarter 2017 and an increase of $13 million in fuel cost recovery. Total retail revenues recorded in 2013 that were reversed in 2014 as a result of thefor 2016 increased $83 million, or 10.7%, compared to 2015 Court decision.
Revenues associated withprimarily due to changes in rates and pricing increasedof $96 million, partially offset by a net decrease in 2015 when compared to 2014, primarily due to $50 millionfuel and other cost recovery of net revenues associated with the implementation of rates for the Kemper IGCC that began in August 2015. In addition, 2014 revenues included the reversal of $11 million for 2013 as a result of the 2015 Court decision.$17 million.
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle"Retail Regulatory Matters – Environmental Compliance Overview" and "Kemper County Energy Facility – Rate Recovery of Kemper IGCC Costs"Recovery" for additional information. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather.
Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside the Company's service territory. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.
Wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Capacity and other | $ | 158 |
| | $ | 160 |
| | $ | 143 |
| $ | 154 |
| | $ | 157 |
| | $ | 158 |
|
Energy | 112 |
| | 163 |
| | 151 |
| 105 |
| | 104 |
| | 112 |
|
Total non-affiliated | $ | 270 |
| | $ | 323 |
| | $ | 294 |
| $ | 259 |
| | $ | 261 |
| | $ | 270 |
|
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of the Company's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
have a significant impact on net income. TheIn addition, the Company servesprovides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.0%19.3% of the Company’sCompany's total operating revenues in 20152017 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Wholesale revenues from sales to non-affiliates decreased $53 million, or 16.4%, in 2015 compared to 2014 primarily as a result of a $51 million decrease in energy revenues, of which $13 million was associated with a decrease in KWH sales and $38 million was associated with lower fuel prices. Wholesale revenues from sales to non-affiliates increased $29 million, or 9.8%, in 2014 compared to 2013 as a result of a $17 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $12 million increase in energy revenues, of which $10 million was associated with an increase in KWH sales and $2 million was associated with higher fuel prices.
Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above the Company's variable cost to produce the energy.
Wholesale revenues from sales to affiliates will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the Intercompany Interchange Contract (IIC), as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Wholesale revenues from sales to affiliates decreased $31increased $30 million, or 29.0%115.4%, in 20152017 compared to 20142016. The increase was primarily due to higher natural gas prices and higher KWH sales due to dispatch of the Company's lower cost generation resources to serve system territorial load. Wholesale revenues from sales to affiliates decreased $50 million, or 65.8%, in 2016 compared to 2015 primarily due to a $31$50 million decrease in energy revenues of which $28$4 million was associated with lower fuel prices and $3$46 million was associated with a decrease in KWH sales. Wholesale revenues from sales to affiliates increased $72 million, or 208.3%,as a result of lower cost generation available in 2014 compared to 2013 primarily due to a $75 million increase in energy revenues of which $69 million was associated with an increase in KWH sales and $5 million was associated with higher prices, partially offset by a decrease in capacity revenues of $2 million.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Powerthe Southern Company 2015 Annual Reportsystem.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 20152017 and the percent change from the prior year were as follows:
| | | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change | Total KWHs | | Total KWH Percent Change | | Weather-Adjusted Percent Change |
| 2015 | | 2015 | | 2014 | | 2015* | | 2014 | 2017 | | 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) | | | | | | | | | (in millions) | | | | | | | | |
Residential | 2,025 |
| | (4.8 | )% | | 1.8 | % | | (0.4 | )% | | (2.3 | )% | 1,944 |
| | (5.2 | )% | | 1.3 | % | | 1.4 | % | | (2.4 | )% |
Commercial | 2,806 |
| | (1.9 | ) | | (0.2 | ) | | (0.4 | ) | | 0.1 |
| 2,764 |
| | (2.7 | ) | | 1.3 |
| | (0.1 | ) | | (2.2 | ) |
Industrial | 4,958 |
| | 0.3 |
| | 4.3 |
| | 0.8 |
| | 4.3 |
| 4,841 |
| | (1.3 | ) | | (1.0 | ) | | (1.3 | ) | | (1.6 | ) |
Other | 40 |
| | (2.1 | ) | | 1.1 |
| | (2.1 | ) | | 1.1 |
| 39 |
| | (1.6 | ) | | (1.3 | ) | | (1.6 | ) | | (1.3 | ) |
Total retail | 9,829 |
| | (1.4 | ) | | 2.4 |
| | 0.2 | % | | 1.6 | % | 9,588 |
| | (2.5 | ) | | 0.1 |
| | (0.4 | )% | | (1.9 | )% |
Wholesale | | | | | | | | | | | | | | | | | | |
Non-affiliated | 3,852 |
| | (8.1 | ) | | 6.7 |
| | | | | 3,672 |
| | (6.3 | ) | | 1.7 |
| | | | |
Affiliated | 2,807 |
| | (3.2 | ) | | 211.4 |
| | | | | 2,024 |
| | 82.7 |
| | (60.5 | ) | | | | |
Total wholesale | 6,659 |
| | (6.1 | ) | | 45.9 |
| | | | | 5,696 |
| | 14.0 |
| | (24.5 | ) | | | | |
Total energy sales | 16,488 |
| | (3.4 | )% | | 16.9 | % | | | | | 15,284 |
| | 2.8 | % | | (9.8 | )% | | | | |
| |
* | In the first quarter 2015, the Company updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances in the above table reflect an adjustment to the estimated allocation of the Company's unbilled 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, 2015 weather-adjusted residential sales decreased 1.8%, commercial sales decreased 2.1% and industrial KWH sales increased 0.3% as compared to the corresponding period in 2014. |
Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales decreased 1.4%2.5% in 20152017 as compared to the prior year. This decrease was primarily the result of milder weather in 2017 as compared to 2016. Weather-adjusted residential KWH sales increased in 2017 primarily due to increased customer usage. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage largely offset by customer growth. The decrease in industrial KWH energy sales was primarily due to Hurricane Nate, which impacted several large industrial customers.
Retail energy sales increased 0.1% in 2016 as compared to the first and fourth quartersprior year. This increase was primarily the result of 2015warmer weather in the third quarter 2016 as compared to the corresponding periodsperiod in 2014.2015. Weather-adjusted residential and commercial KWH sales decreased primarily due to decreased customer usage partially offset by customer growth. Household income, one of the primary drivers of residential customer usage, had modest growth in 2015. The increasedecrease in industrial KWH energy sales was primarily due to expanded operationplanned and unplanned outages by manylarge industrial customers.
Retail energy sales increased 2.4%See "Operating Revenues" above for a discussion of significant changes in 2014 as comparedwholesale revenues to the prior year. This increase was primarily the resultaffiliated companies.
Wholesale energy sales to non-affiliates decreased in 2015 compared to 2014 primarily due to decreased opportunity sales to the external market based on lower demand which was offset by lower system prices. Wholesale energy sales to non-affiliates increased in 2014 compared to 2013 primarily due to increased opportunity sales to the external market as a result of lower system prices.
Wholesale sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of theMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.2017 Annual Report
Wholesale energy sales to affiliates decreased in 2015 compared to 2014 primarily due to lower fuel cost and less sales to affiliate companies. Wholesale energy sales to affiliates increased in 2014 compared to 2013 primarily due to an increase in the Company's generation, resulting in more energy available to sell to affiliate companies.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the single largest expenseexpenses for the Company. The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the Company purchases a portion of its electricity needs from the wholesale market.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
Details of the Company's generation and purchased power were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Total generation (millions of KWHs) | 17,014 |
| | 16,881 |
| | 13,721 |
| |
Total purchased power (millions of KWHs) | 539 |
| | 886 |
| | 1,559 |
| |
Total generation (in millions of KWHs) | | 15,319 |
| | 14,514 |
| | 17,014 |
|
Total purchased power (in millions of KWHs) | | 1,314 |
| | 1,574 |
| | 539 |
|
Sources of generation (percent) – | | | | | | | | | | |
Gas | | 92 |
| | 91 |
| | 83 |
|
Coal | 17 |
| | 42 |
| | 36 |
| 8 |
| | 9 |
| | 17 |
|
Cost of fuel, generated (in cents per net KWH) – | | | | | | |
Gas | 83 |
| | 58 |
| | 64 |
| 2.69 |
| | 2.41 |
| | 2.58 |
|
Cost of fuel, generated (cents per net KWH) – | | | | | | |
Coal | 3.71 |
| | 3.96 |
| | 4.97 |
| 3.64 |
| | 3.91 |
| | 3.71 |
|
Gas | 2.58 |
| | 3.37 |
| | 3.16 |
| |
Average cost of fuel, generated (cents per net KWH) | 2.78 |
| | 3.64 |
| | 3.87 |
| |
Average cost of purchased power (cents per net KWH) | 2.17 |
| | 4.85 |
| | 3.10 |
| |
Average cost of fuel, generated (in cents per net KWH) | | 2.77 |
| | 2.55 |
| | 2.78 |
|
Average cost of purchased power (in cents per net KWH) | | 3.50 |
| | 3.07 |
| | 2.17 |
|
Fuel and purchased power expenses were $455$420 million in 2015,2017, an increase of $43 million, or 11.4%, as compared to the prior year. The increase was primarily due to a $36 million increase in the average cost of generation and purchased power and a net increase of $7 million in KWHs generated from gas generation.
Fuel and purchased power expenses were $377 million in 2016, a decrease of $162$78 million, or 26.3%17.1%, as compared to the prior year. The decrease was primarily due to a $125decrease of $70 million decrease in the costvolume of fuelKWHs generated and purchased power and a decrease of $183 million in KWHs generated by coal generation and purchased power, partially offset by a $146 million increase in KWHs generated by gas generation. Fuel and purchased power expenses were $617 million in 2014, an increase of $77 million, or 14.3%, as compared to the prior year. The increase was primarily due to a $114$8 million increase in the total volume of KWHs generated, offset by a $37 million decrease in theaverage cost of fuelgeneration and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through the Company's fuel cost recovery clauses. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein and Note 1 to the financial statements under "Fuel Costs" for additional information.
Fuel
Fuel expense decreased $131increased $52 million, or 22.8%15.2%, in 20152017 compared to 2014. The decrease was the result2016 primarily due to an 11.6% higher cost of a 23.6%natural gas. Fuel expense decreased $100 million, or 22.6%, in 2016 compared to 2015 due to an 8.2% decrease in the average cost of fuel per KWH generated partially offset byand a 0.9% increase in the volume of KWH generated in 2015. Fuel expense increased $83 million, or 16.8%, in 2014 compared to 2013. The increase was the result of a 24.5% increase15.5% decrease in the volume of KWHs generated in 2014, partially offset by a 5.9% decrease in the average cost of fuel per KWH generated.
Purchased Power - Non-Affiliates
Purchased power expense from non-affiliates decreased $13$9 million, or 72.2%26.5%, in 20152017 compared to 2014.2016. The decrease was primarily the result of a 72.4%16.5% decrease in the average cost per KWH purchased. Purchased power expense from non-affiliates increased $12 million, or 210.3%, in 2014 compared to 2013. The increase was primarily the resultvolume of KWHs purchased offset by a 276.7%slight increase in the average cost per KWH purchased partially offset bycompared to 2016. Purchased power expense increased $22 million, or 183.3%, in 2016 compared to 2015. The increase in 2016 was primarily the result of a 17.6% decrease192.1% increase in the volume of KWHs purchased. The increase in the average cost per KWH purchased was due to a higher marginalthe availability of lower cost energy as compared to the cost of fuel.self-generation.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
Purchased power expense from affiliates decreased $18 million, or 72.0%, in 2015 compared to 2014. The decrease in 2015 was primarily the result of a 58.3% decrease in the volume of KWHs purchased and a 36.9% decrease in the average cost per KWH purchased compared to 2014. Purchased power expense from affiliates decreased $18 million, or 41.1%, in 2014 compared to 2013. The decrease in 2014 was primarily the result of a 49.5% decrease in the volume of KWHs purchased, offset by a 16.8% increase in the average cost per KWH purchased compared to 2013.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
II-371Other operations and maintenance expenses decreased $30 million, or 9.6%, in 2017 compared to the prior year. The decrease was primarily due to a $10 million decrease in transmission and distribution expenses related to overhead line maintenance, an $8 million decrease in contractor services related to facilities, corporate advertising, and employee compensation and benefits, and an $8 million decrease related to the combined cycle and the associated common facilities portion of the Kemper County energy facility.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased $3$38 million, or 1.1%13.9%, in 20152016 compared to the prior year. The increase was primarily relateddue to a $7increases of $28 million increase in employee compensation and benefits, including pension costs and a $6 million increase in generation maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC. See Note 2 toCounty energy facility and $10 million in amortization of prior expense deferrals, both following the financial statements for additional information on pension costs. BeginningIn-Service Asset Rate Order in the third quarterDecember 2015, in connection with the implementation of interim rates associated with the Kemper IGCC, the Company began expensing certain ongoing project costs associated with Kemper IGCC assets placed in service that previously were deferred as regulatory assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and "–Regulatory Assets and Liabilities" herein for additional information. These increases in 2015 were partially offset by decreases of $4well as a $7 million increase in transmission and distribution expenses primarily related to overhead line maintenance and vegetation management $3 million in generation maintenance expenses, primarily due to lower outage costs, and $2 million in overtime labor.
Other operations and maintenance expenses increased $18 million, or 6.8%, in 2014 compared to 2013 primarily due to a $14 million increase in employee compensation and benefit expenses and a $7 million increase in generation maintenance expenses. These increases in 2014 were partially offset by a $2$9 million decrease in transmission expenses primarily related to overhead line maintenance and vegetation management, and a $1 million decrease in customer accounting expenses primarily due to uncollectibles.planned generation outage costs.
Depreciation and Amortization
Depreciation and amortization increased $26$29 million, or 26.8%22.0%, in 20152017 compared to 20142016 primarily due to an $18$13 million increase in depreciationof amortization related to an increase in assetsthe ECO plan, $7 million of depreciation for additional plant in service, and an increase$6 million in the depreciation rates, a $16 million increase due toadditional regulatory asset amortization of regulatory assets associated with the Kemper IGCC,Mercury and a $2Air Toxics Standards (MATS) rule compliance.
Depreciation and amortization increased $9 million, increase resulting from the estimatedor 7.3%, in 2016 compared to 2015 costprimarily due to $32 million of capital as agreed inadditional regulatory asset amortization related to the In-Service Asset Rate Order.Order, ECO plan, and MATS rule compliance, $13 million associated with Kemper County energy facility deferrals primarily related to depreciation deferrals in 2015, and $9 million of depreciation for additional plant in service assets primarily associated with the Plant Daniel scrubbers. These increases were partially offset by decreases$23 million of $5 million in ECO plan amortization, $3 million in Kemper combined cycle costregulatory deferrals and $2 million in deferrals associated with the purchase of Plant Daniel Units 3 and 4. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.
Depreciation and amortization increased $6 million, or 6.3%, in 2014 compared to 2013 primarily due to a $4 million increase related to the reversal ofIn-Service Asset Rate Order and a regulatory$22 million deferral associated with the Kemper IGCC municipal franchise taxes, a $2 million increase in depreciation related to an increase in assets in service, and a $2 million increase resulting from a regulatory deferral associatedimplementation of revised ECO plan rates with the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $4 million decrease associated with a wholesale revenue requirement adjustment.first billing cycle for September 2016.
See Note 1 to the financial statements under "Depreciation and Amortization" and Note 3 to the financial statements under "FERC Matters" and ""Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $5 million, or 4.6%, in 2017 compared to 2016 primarily due to a decrease in franchise taxes of $4 million, as well as a decrease in ad valorem taxes of $1 million. Taxes other than income taxes increased $15 million, or 19.0%16.0%, in 20152016 compared to 20142015 primarily as a result of a $12 million increasedue to increases in ad valorem taxes and a $4of $10 million, related to an increase in the assessed value of property, as well as increases in franchise taxes partially offset by a $1of $5 million, decrease in payroll taxes. Taxes other than income taxes decreased $2 million, or 2.0%, in 2014 comparedrelated to 2013 primarily as a result of a $6 million decrease in franchise taxes, partially offset by a $3 million increase in ad valorem taxes and a $1 million increase in payroll taxes.increased operating revenue.
The retail portion of ad valorem taxes is recoverable under the Company's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Estimated Loss on Kemper IGCC
EstimatedIn 2017, 2016, and 2015, estimated probable losses on the Kemper IGCC of $3.36 billion, $428 million, and $365 million, respectively, were recorded. On June 28, 2017, the Company suspended the gasifier portion of the project and $868 million were recorded in 2015 and 2014, respectively,a charge to reflectearnings for the remaining $2.8 billion book value of the gasifier portion of the project. Prior to the suspension, the Company recorded losses for revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of the Initial DOE Grants and excluding the Cost Cap Exceptions.
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information.
Allowance for Equity Funds Used During Construction
AFUDC equity decreased $26$52 million, or 19.1%41.9%, in 20152017 as compared to 2014. The decrease in 2015 was primarily due to2016 as a reduction in the AFUDC rate driven by an increase in short-term borrowings and placing the combined cycle and the associated common facilities portionresult of the Kemper IGCC project suspension in service in August 2014.June 2017. AFUDC equity increased $14 million, or 12.2%12.7%, in
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
2014 2016 as compared to 2013. The increase in 2014 was2015 primarily due to a higher AFUDC rate and an increase in Kemper County energy facility CWIP relatedsubject to AFUDC prior to the Company's Kemper IGCC.suspension of the gasifier portion of the project, partially offset by placing the Plant Daniel scrubbers in service in November 2015. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Allowance for Funds Used During Construction" herein and Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information regarding the Kemper IGCC.information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased $38$32 million or 84.4%, in 20152017 compared to 2014.2016. The decrease was primarily dueassociated with a $36 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was the amortization of $6 million in interest deferrals in accordance with the In-Service Asset Rate Order and a $58$7 million decrease in interest related to the terminationoutstanding debt as a result of an agreement for SMEPA to purchase a portion of the Kemper IGCC which required the return of SMEPA's deposits at a lower rate of interest than accrued, a $5 million decrease associated with amended tax returns,balances and a $2 million decrease associated with the redemption of long-term debt in 2015.lower rates. These decreases were partially offset by increasesa $20 million reduction in interest capitalized following suspension of the Kemper County energy facility construction.
See Note 5 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Interest expense, net of $10amounts capitalized increased $67 million in 2016 compared to 2015. The increase was primarily due to an increase of $31 million of interest on deposits resulting from the 2015 reversal of interest associated with the termination of an asset purchase agreement between the Company and Cooperative Energy in May 2015; a $20 million increase due to additional issuanceslong-term debt and a $30 million decrease in amounts capitalized primarily resulting from $17 million of debtcapitalized interest and the amortization of $13 million in 2015, $9 million associatedinterest deferrals in accordance with unrecognized tax benefits, and $5 million related to the Mirror CWIP refund,In-Service Asset Rate Order. These net increases were partially offset by a $3decrease of $16 million decrease in interest accrued on the Mirror CWIP liability prior to refund in 2015.
Income Taxes (Benefit)
Income tax benefits increased $428 million, or 411.5%, in 2017 compared to 2016 primarily due to $809 million in tax benefits on the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC debt.equity portion and the related state valuation allowances, partially offset by $372 million resulting from Tax Reform Legislation. Tax Reform Legislation earnings impacts are primarily due to revaluing deferred tax assets related to the Kemper County energy facility. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information.
Interest expense, net of amounts capitalizedIncome tax benefits increased $9$32 million, or 24.2%44.4%, in 20142016 compared to 2013,2015 primarily due toas a result of an $11 million increase in interest expense resulting from the receipt of $125 million interest-bearing refundable deposits from SMEPA, an $8 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery, a $5 million increase in interest expense primarily associated with the issuances of long-term debt in 2014, and a $3 million increase in other interest expense. These increases in 2014 over the prior year were partially offset by a $15 million increase in capitalized interest resulting from carrying costs associated with the Kemper IGCC and a $3 million decrease in interest expense primarily associated with the redemption of long-term debt in late 2013.
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for more information.
Other Income (Expense), Net
Other income (expense), net increased $6 million, or 42.9%, in 2015 compared to 2014 primarily due to $7 million associated with a settlement with the Sierra Club in 2014, partially offset by a $1 million increase in donations. Other income (expense), net decreased $7 million, or 133.7%, in 2014 compared to 2013 primarily due to $7 million associated with a settlement with the Sierra Club and a $1 million increase in consulting fees.
Income Taxes (Benefit)
Income taxes (benefit) increased $213 million, or 74.7%, in 2015 compared to 2014 and increased $83 million, or 22.5%, in 2014 compared to 2013 primarily resulting from the reduction in pre-tax losses related to the estimated probable losses on the Kemper IGCC.IGCC and an increase in AFUDC equity, which is non-taxable.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The Company operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service areaterritory located in southeast Mississippi and to wholesale customers in the Southeast. Prices for electricity provided by the Company to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See "FERC Matters" herein, ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Electric Utility Regulation" herein, and Note 3 to the financial statements for additional information about regulatory matters.
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's business of selling electricity.providing electric service. These factors include the Company's ability to prevail against legal challenges associated with the Kemper IGCC, recover its prudently-incurred costs, in a timely manner during a time of increasing costs, and the completion and subsequent operation ofits ability to prevail against legal challenges associated with the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
PSC, as well as other ongoing construction projects.County energy facility. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a numbervariety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territory. Demand for electricity is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, which may impact future earnings.
The Company's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual return compared to the allowed return range. See "Retail Regulatory Matters" herein and Note 3 to the financial statements under "Retail Regulatory Matters – Performance Evaluation Plan" for more information.
On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on the Company's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
On December 22, 2017, Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters – Federal Tax Reform Legislation" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements for additional information.
The Company provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of the Company's total operating revenues in 2017 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to federal and statethe transmission system. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental statuteslaws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the Company's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed.long-term wholesale agreements. Further, higherincreased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See Note 3 to the financial statements under "Environmental Matters" for additional information.
Environmental Statutes and Regulations
General
The Company's operations are subject to extensive regulation by state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including air, water, and land resources. Applicable statutes include the Clean Air Act; the Clean Water Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with these environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions. Through 2015, the Company had invested approximately $617 million in environmental capital retrofit projects to comply with these requirements, with annual totals of approximately $94 million, $118 million, and $104 million for 2015, 2014, and 2013, respectively. The Company expects that capital expenditures to comply with environmental statutes and regulations will total approximately $66 million from 2016 through 2018, with annual totals of approximately $21 million, $19 million, and $26 million for 2016, 2017, and 2018, respectively. These estimated expenditures do not include any potential capital expenditures that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are not reflected in the capital expenditures above, as these costs are associated with the Company's asset retirement obligation (ARO) liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
The Company's ultimate environmental compliance strategy, including potential unit retirement and replacement decisions, and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations, including the environmental regulations described below; the outcome of any legal challenges to the environmental rules; the cost, availability, and existing inventory of emissions allowances; and the Company's fuel mix. Compliance costs may arise from existing unit retirements, installation of additional environmental controls, closure and monitoring of CCR facilities, and adding or changing fuel sources for certain existing units. The ultimate outcome of these matters cannot be determined at this time. See "Retail Regulatory Matters – Environmental Compliance Overview Plan" herein for additional information.
Compliance with any new federal or state legislation or regulations relating to air, water, and land resources or other environmental and health concerns could significantly affect the Company. Although new or revised environmental legislation or regulations could affect many areas of the Company's operations, the full impact of any such changes cannot be determined at this time. Additionally, many of the Company's commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See Note 3 to the financial statements under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information.
Through 2017, the Company has invested approximately $643 million in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $9 million, $17 million, and $94 million for 2017, 2016, and 2015, respectively. Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, the Company's current compliance strategy estimates capital expenditures of $63 million from 2018 through 2022, with annual totals of approximately $14 million, $16 million, $17 million, $13 million, and $3 million for 2018, 2019, 2020, 2021, and 2022, respectively. These estimates do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Company also anticipates expenditures associated with ash pond closure and ground water monitoring under the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule), which are reflected in the Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
II-374Environmental Laws and Regulations
Air Quality
The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO2), which it reviews and revises periodically. Revisions to these standards can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new facilities. In 2015, the EPA published a more stringent eight-hour ozone NAAQS. The EPA plans to complete designations for this rule by no later than April 30, 2018. No areas within the Company's service territory have been or are anticipated to be designated nonattainment under the 2015 ozone
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Air Quality
Compliance with the Clean Air Act and resulting regulations has been and will continue to be a significant focus for the Company. Additional controls are currently planned or under consideration to further reduce air emissions, maintain compliance with existing regulations, and meet new requirements.
NAAQS. In 2012,2010, the EPA finalizedrevised the Mercury and Air Toxics Standards (MATS) rule, which imposes stringent emissions limits for acid gases, mercury, and particulate matter on coal- and oil-fired electric utility steam generating units. The compliance deadline set by the final MATS rule was April 16, 2015, with provisions for extensions to April 16, 2016. The implementation strategy for the MATS rule includes emission controls, retirements, and fuel conversions to achieve compliance by the deadlines applicable to each Company unit. On June 29, 2015, the U.S. Supreme Court issued a decision finding that in developing the MATS rule the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units. On December 15, 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded the MATS rule to the EPA without vacatur to respond to the U.S. Supreme Court's decision. The EPA's supplemental finding in response to the U.S. Supreme Court's decision, which the EPA proposes to finalize in April 2016, is not expected to have any impact on the MATS rule compliance requirements and deadlines.
The EPA regulates ground level ozone concentrations through implementation of an eight-hour ozone National Ambient Air Quality Standard (NAAQS). On October 26, 2015, the EPA published a more stringent eight-hour ozone NAAQS. This new standard could potentially require additional emission controls, improvements in control efficiency, and operational fuel changes and could affect the siting of new generating facilities. States will recommend area designations by October 2016, and the EPA is expected to finalize them by October 2017.
Final revisions to the NAAQS for sulfur dioxide (SO2), which established a new one-hour standard, became effective in 2010. No areas within the Company's service territory have been designated as nonattainment under this rule. However, the EPA has finalized a data requirements rule to support additional designation decisions for SO2, establishing a new one-hour standard, and is completing designations in multiple phases. The EPA has issued several rounds of area designations and no areas in the future, which could result in nonattainment designations for areas within the Company's service territory. Implementationvicinity of the revisedCompany-owned SO2 standard could require additional reductions insources have been designated nonattainment under the 2010 one-hour SO2 emissionsNAAQS. However, final eight-hour ozone and SO2 one-hour designations for certain areas are still pending and, if other areas are designated as nonattainment in the future, increased compliance and operational costs.costs could result.
In February 2014,2011, the EPA proposed to delete fromfinalized the Alabama State Implementation Plan (SIP) the Alabama opacity rule that the EPA approved in 2008, which provides operational flexibility to affected units, including units co-owned by the Company. In 2013, the U.S. Court of Appeals for the Eleventh Circuit ruled in favor of Alabama Power and the Company and vacated an earlier attempt by the EPA to rescind its 2008 approval. The EPA's latest proposal characterizes the proposed deletion as an error correction within the meaning of the Clean Air Act. Alabama Power and the Company believe this interpretation of the Clean Air Act to be incorrect. If finalized, this proposed action could affect unit availability and result in increased operations and maintenance costs for affected units, including units co-owned by the Company.
The Company's service territory is subject to the requirements of the Cross StateCross-State Air Pollution Rule (CSAPR). and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that limitsaddresses the impacts of the interstate transport of SO2 and nitrogen oxideNOX emissions from fossil fuel-fired power plants located in 28upwind states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,the eastern half of the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, but rejected all other pending challengeson air quality in downwind states. The Company has fossil fuel-fired generation subject to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,these requirements. In October 2016, the EPA published a proposed revision tofinal rule that revised the CSAPR that would revise existing ozone-seasonseasonal NOX program, establishing more stringent NOX emissions budgets for nitrogen oxide in Alabama and Mississippi. The EPA proposesoutcome of ongoing CSAPR litigation, to finalize this rulemaking by summer 2016.which the Company is a party, could have an impact on the State of Mississippi's allowance allocations under the CSAPR seasonal NOX program. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
The EPA finalized regional haze regulations in 2005 with aand 2017. These regulations require states, tribal governments, and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, (primarilyincluding national parks and wilderness areas)areas. States must submit a revised state implementation plan (SIP) to the EPA by 2064. The rule involves the application of best available retrofit technology to certain sources, including fossil fuel-fired generating facilities, built between 1962 and 1977 and any additional emissions reductions necessary for each designated area to achieveJuly 31, 2021, demonstrating reasonable progress toward the naturaltowards achieving visibility conditions goal by 2018 and for each 10-year period thereafter.improvement goals. State implementation of reasonable progress could require further reductions in SO2 or NOX emissions, which could result in increased compliance costs.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units) during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Alabama and Mississippi) to revise or remove the provisions of their SIPs relating to the regulation ofregulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM). The state excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, if removed, could affect unit availability and result in increased operations and maintenance costs for the Company. The EPA has not yet responded to the SIP revisions proposed by no later thanstates where the Company's generating units are located.
Water Quality
In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities in order to minimize their effects on fish and other aquatic life. The regulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). The ultimate impact of this rule will depend on the outcome of these plant-specific studies and any additional protective measures required to be incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule that set national standards for wastewater discharges from steam electric generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates may require extensive modifications to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the ELG rule is expected to require capital expenditures and increased operational costs primarily affecting the Company's coal-fired electric generation. Compliance applicability dates range from November 1, 2018 to December 31, 2023 with state environmental agencies incorporating specific applicability dates in the NPDES permitting process based on information provided for each waste stream. The EPA has committed to a new rulemaking that could potentially revise the limitations and applicability dates of the ELG rule. The EPA expects to finalize this rulemaking in 2020.
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2016.2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
The Company has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the current and proposed environmental requirements discussed above. The impacts of the eight-hour ozone and SO2 NAAQS, the Alabama opacity rule, CSAPR, regional haze regulations, the MATS rule, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisions of the proposed and final rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions and results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
See Note 3 to the financial statements under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information.
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014. The effect of this final rule will depend on the results of additional studies and implementation of the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule. The ultimate impact of this rule will also depend on the outcome of ongoing legal challenges and cannot be determined at this time.
On November 3, 2015, the EPA published a final effluent guidelines rule which imposes stringent technology-based requirements for certain wastestreams from steam electric power plants. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require the installation and operation of multiple technologies sufficient to ensure compliance with applicable new numeric wastewater compliance limits. Compliance deadlines between November 1, 2018 and December 31, 2023 will be established in permits based on information provided for each applicable wastestream. The ultimate impact of these requirements will depend on pending and any future legal challenges, compliance dates, and implementation of the final rule and cannot be determined at this time.
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule became effective August 28, 2015, but on October 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order staying implementation of the final rule. The ultimate impact of the final rule will depend on the outcome of this and other pending legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
These water quality regulations could result in significant additional capital expenditures and compliance costs that could affect future unit retirement and replacement decisions. Also, results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates.
Coal Combustion Residuals
The Company currently manages two electric generating plants in Mississippi and is also part owner of a plant located in Alabama, each with onsite CCR storage units consisting of landfills and surface impoundments (CCR Units). In addition to on-site storage, the Company also sells a portion of its CCR to third parties for beneficial reuse. Individual states regulate CCR and the States of Mississippi and Alabama each have their own regulatory requirements. The Company has an inspection program in place to assist in maintaining the integrity of its coal ash surface impoundments.
On April 17, 2015, the EPA published the CCR Rule in the Federal Register, which became effective on October 19, 2015. The CCR Rule regulatesfinalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in CCR Unitslandfills and surface impoundments (CCR units) at active generating power plants. The CCR Rule does not automatically require closurerequires CCR units to be evaluated against a set of CCR Units but includesperformance criteria and potentially closed if minimum criteria for active and inactive surface impoundments containing CCR and liquids, lateral expansionsare not met. Closure of existing CCR units could require installation of equipment and active landfills. Failureinfrastructure to meetmanage CCR in accordance with the minimum criteria canrule. The EPA has announced plans to reconsider certain portions of the CCR Rule by no later than December 2019, which could result in the required closure of a CCR Unit. Although the EPA does not require individual stateschanges to adopt the final criteria, states have the option to incorporate the federal criteria into their state solid waste management plans in order to regulate CCR in a manner consistent with federal standards. deadlines and corrective action requirements.
The EPA's final rule continuesreconsideration of the CCR Rule is due in part to excludea legislative development that impacts the beneficial usepotential oversight role of state agencies. Under the Water Infrastructure Improvements for the Nation Act, which became law in 2016, states are allowed to establish permit programs for implementing the CCR from regulation.Rule.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
Based on initial cost estimates for closure in place and groundwater monitoring of ash ponds pursuant to the CCR Rule, the Company recorded AROs related to thefor each CCR Rule.unit in 2015. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates. The Company is currently completing an analysis ofcost estimates as necessary. In December 2016, the plan of closure for all ash ponds, including the timing of closure and related cost recovery through regulated rates subject to Mississippi PSC approval. Based on the results of that analysis,granted a CPCN to the Company may accelerate the timing of some ash pond closures which could increase its ARO liabilities from the amounts presently recorded. The ultimate impact ofauthorizing certain projects associated with complying with the CCR Rule cannot be determined atRule. Additionally in this timeorder, the Mississippi PSC also authorized the Company to recover any costs associated with the CPCN, including future monitoring costs, through the ECO clause. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and will depend on the Company's ongoing review of the CCR Rule, the results of initialContractual Obligations" herein and ongoing minimum criteria assessments, and the outcome of legal challenges. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information regarding the Company's AROs as of December 31, 2015.2017.
Environmental Remediation
The Company must comply with other environmental laws and regulations that covergoverning the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company couldmay also incur substantial costs to clean up affected sites. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known impacted sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through its ECO clause.established regulatory mechanisms. The Company may be liablerecognizes a liability for some or all required cleanupenvironmental remediation costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Matters – Environmental Remediation" for additional information.only when it determines a loss is probable and reasonably estimable.
Global Climate Issues
On October 23,In 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governingrules limiting CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishesfossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goalsperformance standards for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. Atunits (known as the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adoptClean Power Plan or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. OnCPP). In February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stayCPP, which will remain in effect through the resolution of the litigation whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit orchallenging the legality of the CPP and any review by the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through PPAs. However, the ultimate financial and operational impact of the final rules on the Company cannot be determined at this time and will depend upon numerous factors, including the Company's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, including legal challenges filed byproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the traditional operating companies; individual state implementation of the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countries and cannot be determined at this time.countries.
The EPA's greenhouse gasGHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2014 greenhouse gas2016 GHG emissions were approximately 117 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2015 greenhouse gas2017 GHG emissions on the same basis is approximately 98 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
FERC Matters
Municipal and Rural Associations Tariff
In 2013, the FERC accepted a settlement agreement entered into by theThe Company with itsprovides wholesale customers which approved, among other things, the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by theelectric service to Cooperative Energy, East Mississippi PSC for certain items. The regulatory treatment includes (i) approval to establish a regulatory asset for the portion of non-capitalizable Kemper IGCC-related costs which have been and will continue to be incurred during the construction period for the Kemper IGCC, (ii) authorization to defer as a regulatory asset, for the 10-year period ending October 2021, the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 (assuming a remaining 30-year life)Electric Power Association, and the revenue requirement assuming the continuationCity of the operating lease regulatory treatment with the accumulated deferred balance at the end of the deferral being amortized into wholesale rates over the remaining life of Plant Daniel Units 3 and 4, and (iii) authority to deferCollins, all located in southeastern Mississippi, under a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules.long-term cost-based, FERC regulated MRA tariff.
In March 2014,2016, the Company reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an increase in the MRA cost-based electric tariff. The settlement agreement, accepted by the FERC in May 2014, provided thatwholesale base ratesrevenues under the MRA cost-based electric tariff, increased approximately $10 million annually, effective May 1, 2014.
Included in this settlement agreement, an adjustment to the Company's wholesale revenue requirement in a subsequent rate proceeding was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, the Company recorded a regulatory assetprimarily as a result of a portionplacing
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper IGCC being placedCounty energy facility-related regulatory assets included in service prior torates under the projected date, which was fully amortized as of December 31, 2015.
On May 13, 2015, the FERC accepted a further settlement agreement betweenover the Company36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and its wholesale customerscharged to forgoexpense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a MRA cost-based electric tariffcorresponding increase by, among other things, increasing thein accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015.AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income.
The Company expects to make a subsequent MRA filing during the second quarter 2018. The filing is estimatedintended to be approximately $14 million annually,consistent with the February 6, 2018 Mississippi PSC order for cost recovery of which $11 million relates to the Kemper IGCC.County energy facility, including the impact of Tax Reform Legislation. The ultimate outcome of this matter cannot be determined at this time.
See Note 3On September 18, 2017, the Company and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the financial statementscurrent arrangement under "FERC Matters" for more information.which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC on October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of the Company's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in the Company's revenues is not expected to be significant through 2020.
Fuel Cost Recovery
The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. Effective January 1, 2016,2018, the wholesale MRA fuel rate decreased $47 million annually. Effective February 1, 2016, the wholesale MB fuel rate decreased $2increased $11 million annually. At December 31, 2015, the amount of2017, over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million, which is included in over-recovered regulatory clause liabilities, current in the balance sheets was $24 million compared to an immaterial balance at December 31, 2014.sheets.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
See Note 3 to the financial statements under "FERC Matters" for more information.
Market-Based Rate Authority
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcomeFERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of this matter cannot be determined at this time.cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Power Supply Agreement
In 2008, the Company entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to 86 MWs. On February 5, 2018, the Company and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Company's transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS amended the terms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
General
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through the Company's base rates. See Note 3 to the financial statements under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information.
In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi.
In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.
On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Renewables
On November 10, 2015, the Mississippi PSC issued three separate orders approving three solar facilities for a combined total of approximately 105 MWs. The Company will purchase all of the energy produced by the solar facilities for the 25-year term of the contracts under three PPAs, two of which have been finalized and one of which remains under negotiation. The projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through the Company's fuel cost recovery mechanism.
Energy Efficiency
In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards.
In June 2014, the Mississippi PSC approved the Company's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. In November 2014, the Mississippi PSC approved the Company's revised compliance filing, which proposed an increase of $7 million in retail revenues for the period December 2014 through December 2015. On December 4, 2015, the Company submitted its annual Energy Efficiency Cost Rider Compliance filing, which included a reduction of $2 million in retail revenues for the year ending December 31, 2016. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
The Company’sCompany's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputingdisputed certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to certain costs included in the 2010 PEP lookback filing, which are currentlyremain under review, also impact the 2012 PEP lookback filing.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.
In March 2014, 2015, 2016, and 2015,2017, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 respectively, which each indicated no surcharge or refund.refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the Company submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of thethese filings to allow more time for review.
In June 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan forOn February 7, 2018, the Company revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and other regulated electric utilities in Mississippi.an increased equity ratio of 55%. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
II-379
On July 6, 2017, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider 2017 compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)On November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing, which included a small decrease in annual retail revenues. The ultimate outcome of this matter cannot be determined at this time.
Mississippi Power Company 2015 Annual ReportSee Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Environmental Compliance Overview Plan
In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In August 2014, the Company entered into a settlement agreement with the Sierra Club that,under which, among other things, required the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which also occurred in August 2014. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018.2018 (and the units were retired in July 2016). The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred onin April 16, 2015), and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas no later than April 2016.(which occurred in June and July 2016, respectively).
In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. This request was madeThe Mississippi PSC approved $41 million and $17 million of costs that were reclassified to minimize the potential rate impact to customers arising from pendingregulatory assets associated with Plant Watson and final environmental regulations which may require the premature retirement of some generating units. As of December 31, 2015, $5 million of Plant Greene County, costsrespectively, for amortization over five-year periods that began in July 2016 and $36 million of costs related to Plant Watson have been reclassified as regulatory assets. These costs are expected to be recovered through the ECO plan and other existing cost recovery mechanisms. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Watson and Greene County in 2016. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC.July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements.
On December 3, 2015,In August 2016, the Mississippi PSC approved the Company's revised ECO filing for 2015, which indicated no change in revenue.
On February 12, 2016, the Company submitted its ECOplan filing for 2016, which requested anthe maximum 2% annual increase in annual revenues, capped at 2% of total retail revenues, ofor approximately $18 million, primarily related to the scrubbers on Plant Daniel Units 1 and 2.2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirementrequirements in excess of the 2%, maximum was deferred for inclusion in the 2017 filing, along with related carrying costs.
On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million will be carried forwardof related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing, along with related carrying costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
On February 14, 2018, the Company submitted its ECO plan filing for 2018, including the effects of Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million, primarily related to the 2017carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. TheOn January 12, 2017, the Mississippi PSC approved the 20162017 retail fuel cost recovery factor, effective February 2017 through January 21, 2016,2018, which will resultresulted in an annual revenue decreaseincrease of approximately $120$55 million. On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2015,2017, the amount of over-recoveredunder-recovered retail fuel costs included in the balance sheetssheet in customer accounts receivable was $71approximately $6 million compared to a $3$37 million under-recovered balanceover recovered at December 31, 2014.2016.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Integrated Coal Gasification Combined CycleAd Valorem Tax Adjustment
The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
System Restoration Rider
In February 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million. These filings were suspended by the Mississippi PSC for review.
On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million. A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing.
On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018.
The ultimate outcome of these matters cannot be determined at this time. See Note 1 to the financial statements under "Provision for Property Damage" for additional information.
Storm Damage Cost Recovery
In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded.
Kemper IGCC County Energy Facility
Overview
Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC willCounty energy facility was designed to utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC willMWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC.County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC,County energy facility construction, the Company constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion in Cost Cap Exceptions. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCCCounty energy facility was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCCCounty energy facility in service usingin August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas in August 2014price forecast had decreased significantly and currently expectsthe estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to placeissue an order (which occurred on July 6, 2017) directing the remainderCompany to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC,County energy facility, given the uncertainty as to its future.
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.
Recoveryapproximately $5.95 billion of the costs subject to the construction cost cap, and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision), and actual costs incurred as of December 31, 2015, are as follows:
|
| | | | | | | | | | | |
Cost Category | 2010 Project Estimate(f) | | Current Cost Estimate(a) | | Actual Costs
|
| (in billions) |
Plant Subject to Cost Cap(b)(g) | $ | 2.40 |
| | $ | 5.29 |
| | $ | 4.83 |
|
Lignite Mine and Equipment | 0.21 | | 0.23 | | 0.23 |
CO2 Pipeline Facilities | 0.14 | | 0.11 | | 0.11 |
AFUDC(c) | 0.17 | | 0.69 | | 0.59 |
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g) | — |
| | 0.01 | | 0.01 |
General Exceptions | 0.05 | | 0.10 | | 0.09 |
Deferred Costs(e)(g) | — |
| | 0.20 | | 0.17 |
Total Kemper IGCC | $ | 2.97 |
| | $ | 6.63 |
| | $ | 6.03 |
|
| |
(a)
| Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016. |
| |
(b) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the$2.88 billioncost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.
|
| |
(c)
| The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
|
| |
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information.
|
| |
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. |
| |
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
|
| |
(g) | Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2015, $3.47 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.41 billion), $2$137 million in other property and investments, $69 million in fossil fuel stock, $45 million in materials and supplies, $21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets inAdditional DOE Grants. In the balance sheet.
Theaggregate, the Company does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Companyhad recorded pre-tax charges to income for revisions toof $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of $365the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($226206 million after tax), $868including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($53685 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax),.
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and $1.1 billion ($681 million after tax) in 2015, 2014, and 2013, respectively. The increases toinclude no recovery for costs associated with the cost estimate in 2015 primarily reflect costs for the extensiongasifier portion of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costsCounty energy facility in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including2018 or at any future date. On February 12, 2018, the refractory lining insideCompany made the gasifiers;required compliance filing with the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result inMississippi PSC. The Kemper
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension ofSettlement Agreement also requires (i) the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.
The Company's analysis of the time needed to complete the start-up and commissioning activitiesCPCN for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respectCounty energy facility to the Kemper IGCC may result from factors including, but not limitedbe modified to labor costslimit it to natural gas combined cycle operation and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding the Company's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Income Tax Matters" herein for additional tax information related to the Kemper IGCC.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or(ii) the Company incurs additional costs to satisfy such parameters, there could befile a material adverse impact on the Company's financial statements.
2013 MPSC Rate Order
In January 2013, the Company entered into a settlement agreementreserve margin plan with the Mississippi PSC that was intended to establishby August 2018.
As of December 31, 2017, the process for resolving matters regarding cost recovery related tobalances associated with the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC,County energy facility regulatory assets and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013liabilities were $114 million and 3% effective January 1, 2014, which collectively were designed to collect $156$26 million, annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.
2015 Rate Caserespectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Court decision, on July 10,Rate Case
On December 3, 2015, the Company filed a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration byissued the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover the Company's costs associated withRate Order regarding the Kemper IGCCCounty energy facility assets that arewere commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued thecosts. The In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between the Company and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, the In-Service Asset Rate Order providesprovided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the Company’sCompany's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period.costs. The In-Service Asset Rate Order also includesincluded a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes
In connection with the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
With implementation of the new rate on December 17, 2015, the interim rates were terminated and the Company recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.
Pursuant to the In-Service Asset Rate Order, the Company is required to file a subsequent rate request within 18 months. As part of the filing, the Company expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. The Company expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact the Company's ability to utilize alternate financing through securitization or the February 2013 legislation.
The Company expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015 of $6.63 billion, the Company anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
The Company expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting the Company the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, the Company requested confirmation by the Mississippi PSC of the Company's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interimwholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortizationfees over periods for these regulatory assets varyranging from two years to 10 years as set forth inyears. On July 6, 2017, the In-Service Asset Rate Order. As of December 31, 2015,Mississippi PSC issued an order requiring the balance associated with theseCompany to establish a regulatory assets was $120 million. Other regulatory assets associated with the remainder ofliability account to maintain current rates related to the Kemper IGCC totaled $96 million asCounty energy facility following the July 2017 completion of December 31, 2015. Thethe amortization period for certain of these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
regulatory assets. See "2013 MPSC Rate Order""FERC Matters" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.
The In-Service Asset Rate Order requires the Company to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital,2016 settlement agreement with the first occurring as of May 31, 2016. As of December 31, 2015, the Company recorded a related regulatory liability of approximately $2 million. See "2015 Rate Case" herein for additional information.wholesale customers.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, theThe Company will ownowns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCCCounty energy facility site. The mine started commercial operation in June 2013.
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managingresponsible for the mining operations. The contract with Liberty Fuels is effectiveoperations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company currently providesprovided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.
In addition, the Company has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. The Company hasrecovery and entered into agreementsan agreement with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as the Company has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015,. Denbury has the right to terminate the contract at any time because the Company has been engageddid not place the Kemper IGCC in ongoing discussions with its off-takers regarding the status of the CO2 delivery schedule as well as other issues related to the CO2 agreements. As a result of discussions with Treetop, on August 3, 2015, the Company agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in the Company's revenues to the extent the Company is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than the Company forecasted to be available to offset customer rate impacts, which could have a material impact on the Company's financial statements. See "Environmental Matters – Global Climate Issues" herein for additional information regarding the Clean Power Plan and related litigation.service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
II-384On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and the Company and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. The Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Terminationcould have a material impact on the Company's results of Proposed Saleoperations, financial condition, and liquidity. The Company intends to vigorously defend itself in this matter and the ultimate outcome of Undivided Interestthis matter cannot be determined at this time.
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against the Company, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to SMEPA
In 2010the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of the Company, Southern Company, and SCS and sought compensatory damages of $100 million, as amended in 2012,well as unspecified punitive damages. Southern Company, the Company, and SMEPA entered into an agreement whereby SMEPA agreedSCS moved to purchasecompel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a 15% undivided interestclaim for arbitration requesting $500 million in the Kemper IGCC.damages. On May 20, 2015, SMEPA notifiedDecember 28, 2017, the Company that it was terminating the agreement. The Company had previously receivedreached a total of $275 million of deposits from SMEPA that were returned by Southern Company to SMEPA,settlement agreement with interest of approximately $26 million, on June 3, 2015, as a result of the termination, pursuant to its guarantee obligation. Subsequently, the Company issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which matures December 1, 2017.
The In-Service Asset ProposalTreetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the related rates approved by the Mississippi PSC excluded any costs associated with the 15% undivided interest. The Company continues to evaluate its alternatives with respect to its investment and the related costs associated with the 15% undivided interest.arbitration was dismissed.
Income Tax Matters
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information about the Kemper IGCC.information.
Income Tax Matters
Federal Tax Reform Legislation
On December 18, 2015,22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Act.
In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $372 million and a $375 million increase in regulatory liabilities as of December 31, 2017, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Mississippi PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the Company's rate filings to reflect the impacts of the Tax Reform Legislation.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus depreciation was extended for qualified propertyDepreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service overafter September 27, 2017 remain eligible for bonus depreciation under the next five years.PATH Act. The PATH Act allowsallowed for 50% bonus depreciation for 2015 2016, and 2017;through 2017, 40% bonus depreciation for 2018;2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result inBased on provisional estimates, approximately $85$50 million of positive cash flows is expected to result from bonus depreciation for the 20152017 tax year and approximately $390$10 million for the 20162018 tax year,year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may not all be fully realized should Southern Company have a NOL in 2016 due2018. See Notes 3 and 5 to a projected net operating loss in the Company's 2016 tax return. Approximately $360 million of the 2016 benefit is dependent upon placing the remainder of the Kemper IGCC in service in 2016.financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes," respectively, for additional information. The ultimate outcome of this matterthese matters cannot be determined at this time.
Investment Tax CreditsThe IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.2017 Annual Report
Section 174 Research and Experimental Deduction
Southern Company, on behalf of the Company, has reflected deductions for research and experimental (R&E)R&E expenditures related to the Kemper IGCCCounty energy facility in its federal income tax calculations forsince 2013 2014, and 2015. In May 2015, Southern Companyfiled amended its 2008 through 2013 federal income tax returns for 2008 through 2013 to also include deductionssuch deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for Kemper IGCC-related R&E expenditures. Due to the uncertainty related tothese deductions. As a result of this tax position,approval, the Company hadrecognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. Also see "Bonus Depreciation" herein. The ultimate outcome of this matter cannot be determined at this time.accrued interest.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In February 2013, the Company submitted a claim under the DeepwaterDeep Horizon Economic and Property Damages Settlement Agreement associated with the oil spill that occurred in April 2010 in the Gulf of Mexico. The ultimate outcome of this matter cannot be determined at this time.
On April 16, 2015,In 2016, the majoritySEC began conducting a formal investigation of assets that supported coal generation at Plant Watson Units 4Southern Company and 5 were retired. The remaining net book value of these two units was approximately $32 million, excluding the reserve for cost of removal,Company concerning the estimated costs and has been reclassified to other regulatory assets, deferred, in accordance with an accounting order from the Mississippi PSC. The Company expects to recover through its rates the remaining book valueexpected in-service date of the retired assets and certain costs, including unusable inventory, associatedKemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.no recommended enforcement action.
The Company expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Electric Utility Regulation
The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper IGCC Estimated Construction Costs, Project Completion Date, andCounty Energy Facility Rate Recovery
During 2015, the Company further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Company does not intend to seek any rate recovery for any costs relatedFor periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grantscosts, project completion date, and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, therate recovery. The Company recorded total pre-tax charges to income for the estimated probable losses onrelated to the Kemper IGCCCounty energy facility of $183$428 million ($113264 million after tax) in the fourth quarter 2015, $1502016, $365 million ($93226 million after tax) in the third quarter 2015, $23$868 million ($14536 million after tax) in the second quarter 2015, $9 million2014, and $1.2 billion ($6729 million after tax) in prior years.
As a result of the first quarter 2015, $70Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as the Company's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($43206 million after tax) in, including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the fourth quarter 2014, $418 million ($258 million after tax) insuspension period prior to conclusion of the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, andKemper Settlement Docket, as well as a charge of $78 million ($48 million after tax) inassociated with the fourth
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
quarter 2012. In the aggregate, since the Kemper County energy facility project started, the Company has incurred charges of $2.4$6.20 billion ($1.54.14 billion after tax) asthrough December 31, 2017. See Note 11 to the financial statements for additional information on the individual charges by quarter.
As a result of changes in the cost estimate above the cost cap for the Kemper IGCC through December 31, 2015.
The Company has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
The Company's revised cost estimate includes costs through August 31, 2016. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expensesPSC order on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimateFebruary 6, 2018, rate recovery for the Kemper IGCC,County energy facility is resolved, subject to any future legal challenges, and the potential impact on results of operations, the Company considers these items to beno longer represents a critical accounting estimates. estimate.
See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate Plans" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
As a result
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company recorded new2017 Annual Report
The cost estimates for AROs for facilities that are subjectrelated to the disposal of CCR Rule. The cost estimates are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place.closure. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. ForBeginning in 2016, the Company has adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense will decreasedecreased by approximately $4 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $1$2 million or less change in total annual benefit expense and a $20$25 million or less change in projected obligations.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 5.99%6.7%, 6.91%6.5%, and 6.89%5.99% for the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, respectively. The AFUDC rate is applied to CWIP consistent with jurisdictional regulatory treatment. AFUDC equity was $72 million, $124 million, and $110 million $136 million,in 2017, 2016, and $122 million,2015, respectively. The decrease in 2015, 2014, and 2013, respectively.2017 resulted from the Kemper County energy facility project suspension in June 2017.
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
II-388Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Recently Issued Accounting Standards
outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revisescapitalization of only the accounting for revenue recognitionservice cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for fiscal yearsperiods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company continues to evaluate the requirements of ASC 606. The ultimateadopted ASU 2017-07 effective January 1, 2018 with no material impact of the new standard has not yet been determined.on its financial statements.
On April 7, 2015,August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting Standards Update (ASU) No. 2015-03, for Hedging ActivitiesInterest – Imputation of Interest (Subtopic 835-30):Simplifying (ASU 2017-12), amending the Presentation of Debt Issuance Costs (hedge accounting recognition and presentation requirements. ASU 2015-03).2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and2017-12 is effective for fiscal years beginning after December 15, 2015. As permitted, the2018, with early adoption permitted. The Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $9 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption ofadopted ASU 2015-03 did not have an2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview and Sources of Capital
Earnings for all periods presented were negatively affected by charges associated with the results of operations, cash flows, or financial condition of the Company.Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" herein and Note 93 to the financial statements for disclosures impacted by ASU 2015-03.additional information.
On May 1, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): DisclosuresThe Company's cash requirements primarily consist of funding ongoing operations, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), effective for fiscal years beginning after December 15, 2015. As permitted,restoration following major storms.
The Company's financial statement presentation contemplates continuation of the Company elected to early adopt the guidance as a going concern as a result of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, orSouthern Company's anticipated ongoing financial conditionsupport of the Company. SeeSpecifically, the Company has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide the Company with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. For additional information, see Note 26 to the financial statements under "Going Concern."
On February 28, 2017, the maturity dates for disclosures impacted by ASU 2015-07.
On November 20, 2015,$551 million in promissory notes to Southern Company were extended to July 31, 2018. In the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted,second quarter 2017, the Company electedborrowed an additional $40 million under a promissory note issued to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. PriorSouthern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to the adoptionCompany. The Company used a portion of ASU 2015-17,the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all deferredof the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax assetsobligations for the quarter ended September 30, 2017 and liabilities were requiredsubsequently repaid the promissory note upon receipt of its income tax refund from the U.S. government related to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-current accumulated deferred income taxes and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an impact on the results of operations, cash flows, or financial condition of the Company.settlement concerning deductible R&E expenditures. See Note 5 to the financial statements for disclosures impacted by ASU 2015-17.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial conditionunder "Section 174 Research and its ability to obtain financing needed for normal business operations and completion of construction and start-up of the Kemper IGCC were adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $371 million of Mirror CWIP rate collections, including associated carrying costs, the termination of the Mirror CWIP rate, and the required recapture of Phase II tax credits. Earnings for the twelve months ended December 31, 2015 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," –"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order," "– 2015 Rate Case," and – "Income Tax Matters – Investment Tax Credits" hereinExperimental Deduction" for additional information.
ThroughAs of December 31, 2015,2017, the Company's current liabilities exceeded current assets by approximately $911 million primarily due to a $900 million unsecured term loan that matures on March 31, 2018. The Company expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. To fund the Company's capital needs over the next 12 months, the Company has incurred non-recoverableintends to utilize operating cash expendituresflows, external security issuances, lines of $1.95 billion and is expected to incur approximately $0.46 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.
In addition to funding normal business operations and projected capital expenditures, the Company's near-term cash requirements primarily consist of $900 million ofcredit, bank term loans, scheduledequity contributions from Southern Company, and, to mature on April 1, 2016, $300 million in senior notes scheduledthe extent necessary, loans from Southern Company.
The Company's capital expenditures and debt maturities are expected to mature on October 15, 2016, $25 millionmaterially exceed operating cash flows through 2022. The Company plans to obtain the funds required for construction and other purposes from operating cash flows, lines of short-term debt, and the required refund of approximately $11 million in customercredit,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
refunds associated with the In-Service Asset Rate Order. For the three-year period from 2016 through 2018, the Company's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In additionbank term loans, external security issuances, commercial paper, to the Kemper IGCC, projected capital expenditures in that period include investmentsextent the Company is eligible to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units,participate, and to expand and improve transmission and distribution facilities. The Company expects to refinance its 2016 debt maturities with bank term loans. The Company intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances,and/or equity contributions from Southern Company to fund the remainder of the Company's capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities herein for additional information.Company.
The Company's investments in the qualified pension plan remained stableincreased in value as of December 31, 20152017 as compared to December 31, 2014.2016. No contributions to the qualified pension plan were made for the year ended December 31, 2015,2017 and no mandatory contributions to the qualified pension plan are anticipated during 2016.2018.
Net cash provided from operating activities totaled $173$503 million for 2015, a decrease2017, an increase of $562$274 million as compared to 2014.2016. The decreaseincrease in net cash provided from operating activities in 2017 was primarily due to lowertax refunds associated with the approval by the JCT of the Section 174 R&E tax deductions and lower incremental benefit of ITCs relatingsettlement, largely offset by a decrease in income taxes related to the Kemper IGCC reducing income tax refunds, as well as a decrease in the Mirror CWIP regulatory liability due to the Mirror CWIP refund, partially offset by increases in over recovered regulatory clause revenuesCounty energy facility and customer liability associated with the Mirror CWIP refund.Tax Reform Legislation. Net cash provided from operating activities totaled $735$229 million for 2014,2016, an increase of $287$56 million as compared to the corresponding period in 2013.2015. The increase in net cash provided from operating activities in 2016 was primarily due to deferred income taxes and Mirror CWIP rate collections, netrepayment in 2015 of ITCs relating to the Kemper IGCC regulatory deferral,County energy facility, as well as the 2015 mirror CWIP refund, partially offset by a decrease in ITCs receivedlower income tax benefits related to the Kemper IGCC, an increaseCounty energy facility in prepaid income taxes, increases2016 and lower fuel rates in fossil fuel stock, and an increase in regulatory assets associated with the Kemper IGCC.2016.
Net cash used for investing activities in 2017, 2016, and 2015 2014,totaled $504 million, $697 million, and 2013 totaled $0.9 billion, $1.3 billion, and $1.6 billion,$906 million, respectively. The cash used for investing activities in each of theseall years presented was primarily due to gross property additions related to the Kemper IGCC andCounty energy facility. The cash used for investing activities in 2016 was partially offset by the receipt of Additional DOE Grants. The cash used for investing activities in 2015 also included gross property additions related to the Plant Daniel scrubber project.
Net cash provided from financing activities totaled $25 million in 2017 primarily due to capital contributions from Southern Company, largely offset by redemptions of long-term debt and short-term borrowings. Net cash provided from financing activities totaled $594 million in 2016 primarily due to long-term debt financings and capital contributions from Southern Company, partially offset by a decrease in short-term borrowings and redemptions of long-term debt. Net cash provided from financing activities totaled $698 million in 2015 primarily due to short-term borrowings, capital contributions from Southern Company, and long-term debt financings, partially offset by redemptions of long-term debt. Net cash provided from financing activities totaled $593 million in 2014 primarily due to capital contributions from Southern Company, long-term debt financings, and the receipts of interest bearing refundable deposits previously pending, partially offset by redemptions of long-term debt. Net cash provided from financing activities totaled $1.2 billion in 2013 primarily due to an increase in capital contributions from Southern Company and an increase in long-term debt financings, partially offset by redemptions of long-term debt.
Significant balance sheet changes as of December 31, 20152017 compared to 2014 included2016 include decreases of $2.5 billion in CWIP, a net change of $1.0 billion in accumulated deferred income taxes, an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year – other. Securities due within one year – parent decreased $551 million due to the repayment of promissory notes payableto Southern Company. Other significant balance sheet changes include $326 million in deferred charges related to income taxes. All of $500 million.these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable non-current increased $544 million due toand unrecognized tax benefits associated with R&E expenditures for the 2008 through 2013 amendedalso decreased due to tax returns. Total property, plant, and equipment increased $512 million and Mirror CWIP decreased $271 million primarilyrefunds associated with the construction and collections forapproval by the Kemper IGCC.JCT of the Section 174 R&E settlement. The Company also had an increase of $365 million in deferred credits related to income taxes primarily resulting from the impacts of Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Accumulated deferred income taxes increased $582 million primarily due to R&E tax deductions"Kemper County Energy Facility" and accumulated deferred investment tax credits decreased $278 million, due to the recapture of Phase II tax credits. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – InvestmentFederal Tax Credits"Reform Legislation" herein for additional information. Total common stockholder's equity increased $275 million dueand Notes 3 and 5 to the receipt of capital contributions from Southern Company. Other regulatory assets, deferred, increased $140 million primarily due to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" hereinfinancial statements under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction," respectively, for additional information.
The Company's ratio of common equity to total capitalization including long-termplus short-term debt was 39% and 49% at December 31, 2017 and 2016, respectively. The decrease was due within one year, was 47.1% in 2015 and 46.1% in 2014.to Kemper IGCC losses. See Note 6 to the financial statements for additional information.
Sources of Capital
As discussed above, the Company's financial condition and its ability to obtain funds needed for normal business operations and completion of the construction and start-up of the Kemper IGCC were adversely affected in 2015 by events relating to the Kemper IGCC. On December 3, 2015, the Mississippi PSC approved the In-Service Asset Rate Order which, among other things, provides for retail rate recovery of an annual revenue requirement of approximately $126 million which became effective on December 17, 2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case," herein for additional information. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See "Capital Requirements and Contractual Obligations" herein and FUTURE EARNINGS POTENTIAL –
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
"Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order," and " – 2015 Rate Case" herein for additional information.
In April 2015, the Company entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. The Company also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. In addition, the Company received $275 million in equity contributions from Southern Company and issued two promissory notes for up to $676 million to Southern Company bearing interest based on one-month LIBOR. As of December 31, 2015, an aggregate of $576 million was outstanding under these promissory notes, all maturing in December 2017. On January 28, 2016, the Company issued a further promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During January 2016, the Company borrowed $150 million pursuant to the existing promissory notes.
As of December 31, 2015, the Company's current liabilities exceeded current assets by approximately $1.3 billion primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016 and $300 million in senior notes scheduled to mature on October 15, 2016. The Company expects to refinance its 2016 debt maturities with bank term loans. The Company intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund the remainder of the Company's capital needs.
The Company received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
The Company expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.
The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offeringsoffering of securities, are required to be registeredthe Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in raising capital. Any future financing through secured debt would also require approval by the Mississippi PSC.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
At December 31, 2015,2017, the Company had approximately $98$248 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 20152017 were as follows:$100 million, all of which is unused. In November 2017, the Company amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Expires | | | | | | Executable Term-Loans | | Due Within One Year |
2016 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) | | (in millions) |
$ | 220 |
| | $ | 220 |
| | $ | 195 |
| | $ | 30 |
| | $ | 15 |
| | $ | 45 |
| | $ | 175 |
|
See Note 6A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to the financial statements under "Bank Credit Arrangements" for additional information.Company's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of December 31, 2017 was approximately $40 million. In addition, the Company had approximately $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode subsequent to December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Most of these bank credit arrangements, as well as the Company's term loan agreement, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness (including guarantee obligations) of the Company. Such cross defaultcross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross acceleration provisions to other indebtedness would trigger an eventevent of default if the Company defaulted on indebtedness, the payment of which was then accelerated. Theaccelerated. At December 31, 2017, the Company iswas in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, the Company expects to seek to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowing were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 4 |
| | 3.8 | % | | $ | 18 |
| | 3.0 | % | | $ | 36 |
|
December 31, 2016 | $ | 23 |
| | 2.6 | % | | $ | 112 |
| | 2.0 | % | | $ | 500 |
|
December 31, 2015 | $ | 500 |
| | 1.4 | % | | $ | 372 |
| | 1.3 | % | | $ | 515 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31. |
Financing Activities
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Bank Term Loans and Senior Notes
In March 2017, the Company issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In June 2017, the Company used a portion of the proceeds from Southern Company equity contributions to prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018, and to repay $10 million of the outstanding principal amount of bank loans. See "Parent Company Loans and Equity Contributions" herein for more information.
This unsecured term loan has covenants that limit debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes the long-term debt payable to affiliated trusts and other hybrid securities. In addition, this unsecured term loan contains cross-acceleration provisions to other debt (including guarantee obligations) that would be triggered if the Company defaulted on debt above a specified threshold, the payment of which was then accelerated. The Company is currently in compliance with all such covenants.
In August 2017, the Company repaid a $12.5 million short-term bank note.
In November 2017, the Company repaid at maturity $35 million aggregate principal amount of Series 2007A 5.60% Senior Notes.
Parent Company Loans and Equity Contributions
In February 2017, the Company amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
A portion of the $195 million unused credit arrangements with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2015 was $40 million.
The Company may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of the Company and the other traditional operating companies. Proceeds from such issuances for the benefit of the Company are loaned directly to the Company. The obligations of each traditional operating company under these arrangements are several and there is no cross affiliate credit support. The Company has not issued any commercial paper through this program since 2013 and does not intend to make any issuances during 2016.
The Company had no short-term borrowings in 2014. Details of short-term borrowing for 2013 and 2015 were as follows:
|
| | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2015 | $500 | | 1.4% | | $372 | | 1.3% | | $515 |
December 31, 2013 | $— | | —% | | $23 | | 0.2% | | $148 |
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31. |
Financing Activities
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm restoration costs, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Bank Term Loans
In March 2015, the Company repaid at maturity a $75 million bank term loan.
In April 2015, the Company entered into two short-term floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including the Company's ongoing construction program. The Company also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts, other hybrid securities, and securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2015, the Company was in compliance with its debt limits.
In addition, these bank loans contain cross default provisions to other debt (including guarantee obligations) that would be triggered if the Company defaulted on debt above a specified threshold. The Company is currently in compliance with all such covenants.
Other Obligations
In June 2015,September 2017, the Company issued an additional floating rate promissory note to Southern Company. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposits in connection with the termination of the APA. In December 2015, the $301 million promissory note was amended which, among other things, changed the maturity date to December 1, 2017. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" for additional information.
In November 2015, the Company issued an additionala floating rate promissory note to Southern Company in an aggregate principal amount of up to $375$150 million which maturesbearing interest based on December 1, 2017. As of December 31, 2015, theone-month LIBOR. The Company had borrowed $275$109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note. On January 19, 2016,note upon receipt of its income tax refund from the Company borrowedU.S. federal government related to the remaining $100 million. Also, subsequentsettlement concerning deductible R&E expenditures. See Note 5 to December 31, 2015, the Company issued anfinancial statements under "Section 174 Research and Experimental Deduction" for additional floating rate promissory note to Southern Company in
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
an aggregate principal amount of up to $275 million, which matures on December 1, 2017. The Company has borrowed $50 million under the promissory note.information.
Credit Rating Risk
TheAt December 31, 2017, the Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of the Company's credit rating to below investment grade by two of the three rating agencies.
There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At December 31, 2015,2017, the maximum amount of potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $267$241 million.
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more Southern Company system power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets, and would be likely to impactor at a minimum the cost at which it does so.
On June 5, 2015, Fitch Ratings, Inc. (Fitch) downgraded the long-term issuer default rating of the Company to BBB+ from A-. Fitch maintained the negative ratings outlook for the Company.
On August 14, 2015,March 1, 2017, Moody's downgraded the senior unsecured debt rating of the Company to Baa2Ba1 from Baa1. Moody's maintained the negative ratings outlook for the Company.Baa3.
On August 17, 2015, S&P downgraded the issuer rating of the Company to BBB+ from A. S&P revised its credit rating outlook from negative to stable. Separately, on AugustMarch 24, 2015,2017, S&P revised its consolidated credit rating outlook offor Southern Company and its subsidiaries (including the Company) from stable to negative following the announcement of the proposed merger of a wholly-owned direct subsidiary of Southern Company with and into AGL Resources Inc.negative.
On November 5, 2015, Moody's downgradedMarch 30, 2017, Fitch placed the senior unsecured debt ratingratings of the Company to Baa3 from Baa2.on rating watch negative.
On June 22, 2017, Moody's maintainedplaced the negative ratings of the Company on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for the Company.Company from under review to stable.
While it is unclear how the credit rating agencies, the FERC, and the Mississippi PSC may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, the Company may enter into derivatives that have been designated as hedges. The weighted average interest rate on $1 billion$40 million of long-term variable interest rate exposure at December 31, 20152017 was 1.66%2.49%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affecthave an immaterial effect on annualized interest expense by approximately $10 million at January 1, 2016.December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. The Company had no material change in market risk exposure for the year ended December 31, 20152017 when compared to the year ended December 31, 2014.2016.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
| | | 2015 Changes | | 2014 Changes | 2017 Changes | | 2016 Changes |
| Fair Value | Fair Value |
| (in millions) | (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (45 | ) | | $ | (5 | ) | $ | (7 | ) | | $ | (47 | ) |
Contracts realized or settled | 33 |
| | (3 | ) | 8 |
| | 29 |
|
Current period changes(*) | (35 | ) | | (37 | ) | (8 | ) | | 11 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (47 | ) | | $ | (45 | ) | $ | (7 | ) | | $ | (7 | ) |
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, all of which are natural gas swaps, for the years ended December 31 were as follows:
|
| | | | | |
| 2015 | | 2014 |
| mmBtu Volume |
| (in millions) |
Total hedge volume | 32 |
| | 54 |
|
|
| | | | | |
| 2017 | | 2016 |
| mmBtu Volume |
| (in millions) |
Total hedge volume | 53 |
| | 36 |
|
For natural gas hedges, the weighted average swap contract cost above market prices was approximately $1.49$0.14 per mmBtu as of December 31, 20152017 and $0.84$0.19 per mmBtu as of December 31, 2014. There were no2016. The options outstanding as ofwere immaterial for the reporting periods presented. The costs associated with natural gas hedges are recovered through the Company's ECMs.
At December 31, 20152017 and 2014,2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2.2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 20152017 were as follows:
| | | Fair Value Measurements December 31, 2015 | Fair Value Measurements December 31, 2017 |
| Total | | Maturity | Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 | Fair Value | | Year 1 | | Years 2&3 |
| (in millions) | (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (47 | ) | | (29 | ) | | (18 | ) | (7 | ) | | (5 | ) | | (2 | ) |
Level 3 | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (47 | ) | | $ | (29 | ) | | $ | (18 | ) | $ | (7 | ) | | $ | (5 | ) | | $ | (2 | ) |
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements.
Capital Requirements and Contractual Obligations
Approximately $900 million will be required through December 31, 20162018 to fund maturities of bank term loans scheduledlong-term debt. In addition, the Company has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to mature on April 1, 2016, $300 million in senior notes scheduledan index rate mode subsequent to mature on October 15, 2016,December 31, 2017. See "Overview and $25 million in short-term debt. See "SourcesSources of Capital" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
The construction program of the Company is currently estimated to total $787 million for 2016, $216 million for 2017, and $264be $213 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $612$199 million in 2016.for 2019, $193 million for 2020, $167 million for 2021, and $118 million for 2022. These estimated program amounts also include capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statuteslaws and regulations included in these amounts are $21$14 million, $19$16 million, $17 million, $13 million, and $26$3 million for 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. These estimated expenditures do not include any potential compliance costs that may arise fromassociated with the EPA's final rules and guidelines or subsequently approved state plans that would limitregulation of CO2 emissions from new, existing, and modified or reconstructed fossil-fuel-firedfossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental StatutesLaws and Regulations" and "– Global Climate Issues" and – "Integrated Coal Gasification Combined Cycle" herein for additional information.
The Company also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $39$23 million, $12$7 million, $7 million, $9 million, and $11$12 million for the years 2016, 2017,2018, 2019, 2020, 2021, and 2018,2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information and further risksIn addition, there can be no assurance that costs related to the estimated schedule and costs and rate recovery for the Kemper IGCC.capital expenditures will be fully recovered.
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, unrecognized tax benefits, pension and other post-retirement benefit plans, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
| | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| (in millions) | (in millions) |
Long-term debt(a) — | | | | | | | | | | | | | | | | | | |
Principal | $ | 725 |
| | $ | 611 |
| | $ | 132 |
| | $ | 1,026 |
| | $ | 2,494 |
| $ | 990 |
| | $ | 125 |
| | $ | 270 |
| | $ | 673 |
| | $ | 2,058 |
|
Interest | 87 |
| | 132 |
| | 114 |
| | 670 |
| | 1,003 |
| 86 |
| | 106 |
| | 79 |
| | 552 |
| | 823 |
|
Preferred stock dividends(b) | 2 |
| | 3 |
| | 3 |
| | — |
| | 8 |
| 2 |
| | 3 |
| | 3 |
| | — |
| | 8 |
|
Financial derivative obligations(c) | 29 |
| | 18 |
| | — |
| | — |
| | 47 |
| 6 |
| | 3 |
| | — |
| | — |
| | 9 |
|
Unrecognized tax benefits(d) | — |
| | 421 |
| | — |
| | — |
| | 421 |
| |
Operating leases (e) | 2 |
| | 2 |
| | 1 |
| | — |
| | 5 |
| |
Capital leases(f) | 3 |
| | 6 |
| | 7 |
| | 61 |
| | 77 |
| |
Operating leases(d) | | 3 |
| | 5 |
| | 4 |
| | 7 |
| | 19 |
|
Purchase commitments — | | | | | | | | | | | | | | | | | | |
Capital(g) | 752 |
| | 453 |
| | — |
| | — |
| | 1,205 |
| |
Fuel(h) | 142 |
| | 229 |
| | 191 |
| | 254 |
| | 816 |
| |
Long-term service agreements(i) | 34 |
| | 65 |
| | 50 |
| | 215 |
| | 364 |
| |
Pension and other postretirement benefits plans(j) | 7 |
| | 14 |
| | — |
| | — |
| | 21 |
| |
Capital(e) | | 213 |
| | 379 |
| | 269 |
| | — |
| | 861 |
|
Fuel(f) | | 280 |
| | 329 |
| | 191 |
| | 175 |
| | 975 |
|
Long-term service agreements(g) | | 33 |
| | 75 |
| | 49 |
| | 245 |
| | 402 |
|
Purchased power(h) | | 11 |
| | 29 |
| | 36 |
| | 454 |
| | 530 |
|
Pension and other postretirement benefits plans(i) | | 7 |
| | 15 |
| | — |
| | — |
| | 22 |
|
Total | $ | 1,783 |
| | $ | 1,954 |
| | $ | 498 |
| | $ | 2,226 |
| | $ | 6,461 |
| $ | 1,631 |
| | $ | 1,069 |
| | $ | 901 |
| | $ | 2,106 |
| | $ | 5,707 |
|
| |
(a) | All amounts are reflected based on final maturity dates.dates except for amounts related to certain revenue bonds. The Company plans to continue, when economically feasible, to retire higher-cost securitiessecurities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of January 1, 2016,December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). For additional information, see Note 6 to the financial statements. |
| |
(b) | Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Derivative obligations are for energy-related derivatives. For additional information, see Notes 1 and 10 to the financial statements. |
| |
(d) | See Note 5 to the financial statements under "Unrecognized Tax Benefits" for additional information. |
| |
(e) | See Note 7 to the financial statements for additional information. |
| |
(f)(e) | Capital lease related to a 20-year nitrogen supply agreement for the Kemper IGCC. See Note 6 to the financial statements for additional information. |
| |
(g) | The Company provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. At DecemberDecember 31, 2015,2017, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" hereinMatters" for additional information. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle" for additional information. |
| |
(h)(f) | IncludesFuel commitments to purchaseinclude coal and natural gas purchases, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(i)(g) | Long-term service agreements include price escalation based on inflation indices. |
| |
(j)(h) | Purchased power represents estimated minimum long-term commitments for the purchase of solar energy. Energy costs associated with solar PPAs are recovered through the fuel clause. See Notes 3 and 7 to the financial statements for additional information. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, customer and sales growth, economic recovery,conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan and postretirement benefit plans contributions, financing activities, completion of construction projects and changing fuel sources, filings with state and federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC);
the ability to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, andincluding the requirements of any tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
actionslitigation related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;County energy facility;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2015 Annual Report
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF OPERATIONS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Mississippi Power Company 20152017 Annual Report
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Retail revenues | $ | 776 |
| | $ | 795 |
| | $ | 799 |
| $ | 854 |
| | $ | 859 |
| | $ | 776 |
|
Wholesale revenues, non-affiliates | 270 |
| | 323 |
| | 294 |
| 259 |
| | 261 |
| | 270 |
|
Wholesale revenues, affiliates | 76 |
| | 107 |
| | 35 |
| 56 |
| | 26 |
| | 76 |
|
Other revenues | 16 |
| | 18 |
| | 17 |
| 18 |
| | 17 |
| | 16 |
|
Total operating revenues | 1,138 |
| | 1,243 |
| | 1,145 |
| 1,187 |
| | 1,163 |
| | 1,138 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 443 |
| | 574 |
| | 491 |
| 395 |
| | 343 |
| | 443 |
|
Purchased power, non-affiliates | 5 |
| | 18 |
| | 6 |
| |
Purchased power, affiliates | 7 |
| | 25 |
| | 43 |
| |
Purchased power | | 25 |
| | 34 |
| | 12 |
|
Other operations and maintenance | 274 |
| | 271 |
| | 253 |
| 282 |
| | 312 |
| | 274 |
|
Depreciation and amortization | 123 |
| | 97 |
| | 91 |
| 161 |
| | 132 |
| | 123 |
|
Taxes other than income taxes | 94 |
| | 79 |
| | 81 |
| 104 |
| | 109 |
| | 94 |
|
Estimated loss on Kemper IGCC | 365 |
| | 868 |
| | 1,102 |
| 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 1,311 |
| | 1,932 |
| | 2,067 |
| 4,329 |
| | 1,358 |
| | 1,311 |
|
Operating Loss | (173 | ) | | (689 | ) | | (922 | ) | (3,142 | ) | | (195 | ) | | (173 | ) |
Other Income and (Expense): | | | | | | | | | | |
Allowance for equity funds used during construction | 110 |
| | 136 |
| | 122 |
| 72 |
| | 124 |
| | 110 |
|
Interest expense, net of amounts capitalized | (7 | ) | | (45 | ) | | (36 | ) | (42 | ) | | (74 | ) | | (7 | ) |
Other income (expense), net | (8 | ) | | (14 | ) | | (7 | ) | (8 | ) | | (7 | ) | | (8 | ) |
Total other income and (expense) | 95 |
| | 77 |
| | 79 |
| 22 |
| | 43 |
| | 95 |
|
Loss Before Income Taxes | (78 | ) | | (612 | ) | | (843 | ) | (3,120 | ) | | (152 | ) | | (78 | ) |
Income taxes (benefit) | (72 | ) | | (285 | ) | | (368 | ) | (532 | ) | | (104 | ) | | (72 | ) |
Net Loss | (6 | ) | | (327 | ) | | (475 | ) | (2,588 | ) | | (48 | ) | | (6 | ) |
Dividends on Preferred Stock | 2 |
| | 2 |
| | 2 |
| 2 |
| | 2 |
| | 2 |
|
Net Loss After Dividends on Preferred Stock | $ | (8 | ) | | $ | (329 | ) | | $ | (477 | ) | $ | (2,590 | ) | | $ | (50 | ) | | $ | (8 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 20152017, 20142016, and 20132015
Mississippi Power Company 20152017 Annual Report
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Net Loss | $ | (6 | ) | | $ | (327 | ) | | $ | (475 | ) | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Other comprehensive income (loss): | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $(1), $1, and $-, respectively | | (1 | ) | | 1 |
| | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
Total other comprehensive income (loss) | 1 |
| | 1 |
| | 1 |
| — |
| | 2 |
| | 1 |
|
Comprehensive Loss | $ | (5 | ) | | $ | (326 | ) | | $ | (474 | ) | $ | (2,588 | ) | | $ | (46 | ) | | $ | (5 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Mississippi Power Company 20152017 Annual Report
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Operating Activities: | | | | | | | | | | |
Net loss | $ | (6 | ) | | $ | (327 | ) | | $ | (475 | ) | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Adjustments to reconcile net loss to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization, total | 126 |
| | 104 |
| | 92 |
| 198 |
| | 157 |
| | 126 |
|
Deferred income taxes | 777 |
| | 145 |
| | (396 | ) | (727 | ) | | (67 | ) | | 777 |
|
Investment tax credits | (210 | ) | | (38 | ) | | 144 |
| — |
| | — |
| | (210 | ) |
Allowance for equity funds used during construction | (110 | ) | | (136 | ) | | (122 | ) | (72 | ) | | (124 | ) | | (110 | ) |
Pension, postretirement, and other employee benefits | 10 |
| | (29 | ) | | 14 |
| |
Pension and postretirement funding | | — |
| | (47 | ) | | — |
|
Regulatory assets associated with Kemper IGCC | (61 | ) | | (72 | ) | | (35 | ) | (19 | ) | | (12 | ) | | (61 | ) |
Estimated loss on Kemper IGCC | 365 |
| | 868 |
| | 1,102 |
| 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | (544 | ) | | — |
| | — |
| — |
| | — |
| | (544 | ) |
Other, net | (2 | ) | | 18 |
| | 107 |
| (12 | ) | | (20 | ) | | 8 |
|
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | 28 |
| | (22 | ) | | (25 | ) | 540 |
| | 13 |
| | 28 |
|
-Fossil fuel stock | (4 | ) | | 13 |
| | 63 |
| 24 |
| | 4 |
| | (4 | ) |
-Materials and supplies | (13 | ) | | (15 | ) | | (11 | ) | |
-Prepaid income taxes | (35 | ) | | (50 | ) | | 17 |
| — |
| | 39 |
| | (35 | ) |
-Other current assets | (1 | ) | | (4 | ) | | (4 | ) | (13 | ) | | (12 | ) | | (14 | ) |
-Other accounts payable | (34 | ) | | 33 |
| | 13 |
| |
-Accounts payable | | (3 | ) | | (14 | ) | | (34 | ) |
-Accrued interest | (2 | ) | | 29 |
| | 17 |
| (29 | ) | | 27 |
| | (2 | ) |
-Accrued taxes | (11 | ) | | 39 |
| | 11 |
| 80 |
| | 14 |
| | (11 | ) |
-Over recovered regulatory clause revenues | 96 |
| | (18 | ) | | (59 | ) | (51 | ) | | (45 | ) | | 96 |
|
-Mirror CWIP | (271 | ) | | 180 |
| | — |
| — |
| | — |
| | (271 | ) |
-Customer liability associated with Kemper refunds | 73 |
| | — |
| | — |
| (1 | ) | | (73 | ) | | 73 |
|
-Other current liabilities | 2 |
| | 17 |
| | (5 | ) | (3 | ) | | 9 |
| | 2 |
|
Net cash provided from operating activities | 173 |
| | 735 |
| | 448 |
| 503 |
| | 229 |
| | 173 |
|
Investing Activities: | | | | | | | | | | |
Property additions | (857 | ) | | (1,257 | ) | | (1,641 | ) | (429 | ) | | (798 | ) | | (857 | ) |
Investment in restricted cash | — |
| | (11 | ) | | — |
| |
Distribution of restricted cash | — |
| | 11 |
| | — |
| |
Cost of removal net of salvage | (14 | ) | | (13 | ) | | (10 | ) | |
Construction payables | (9 | ) | | (50 | ) | | (50 | ) | (47 | ) | | (26 | ) | | (9 | ) |
Proceeds from asset sales | — |
| | — |
| | 79 |
| |
Government grant proceeds | | — |
| | 137 |
| | — |
|
Other investing activities | (26 | ) | | (20 | ) | | 19 |
| (28 | ) | | (10 | ) | | (40 | ) |
Net cash used for investing activities | (906 | ) | | (1,340 | ) | | (1,603 | ) | (504 | ) | | (697 | ) | | (906 | ) |
Financing Activities: | | | | | | | | | | |
Decrease in notes payable, net | | (18 | ) | | — |
| | — |
|
Proceeds — | | | | | | | | | | |
Capital contributions from parent company | 277 |
| | 451 |
| | 1,077 |
| 1,002 |
| | 627 |
| | 277 |
|
Bonds — Other | — |
| | 23 |
| | 42 |
| |
Interest-bearing refundable deposit | — |
| | 125 |
| | — |
| |
Long-term debt issuance to parent company | 275 |
| | 220 |
| | — |
| 40 |
| | 200 |
| | 275 |
|
Other long-term debt issuances | — |
| | 250 |
| | 475 |
| |
Other long-term debt | | — |
| | 1,200 |
| | — |
|
Short-term borrowings | 505 |
| | — |
| | — |
| 109 |
| | — |
| | 505 |
|
Redemptions — | | | | | | | | | | |
Bonds — Other | — |
| | (34 | ) | | (83 | ) | |
Short-term borrowings | | (109 | ) | | (478 | ) | | (5 | ) |
Long-term debt to parent company | | (591 | ) | | (225 | ) | | — |
|
Capital leases | | (71 | ) | | (3 | ) | | (3 | ) |
Senior notes | — |
| | — |
| | (50 | ) | (35 | ) | | (300 | ) | | — |
|
Other long-term debt | (350 | ) | | (220 | ) | | (125 | ) | (300 | ) | | (425 | ) | | (350 | ) |
Return of paid in capital | — |
| | (220 | ) | | (105 | ) | |
Payment of preferred stock dividends | (2 | ) | | (2 | ) | | (2 | ) | |
Payment of common stock dividends | — |
| | — |
| | (72 | ) | |
Other financing activities | (7 | ) | | — |
| | (2 | ) | (2 | ) | | (2 | ) | | (1 | ) |
Net cash provided from financing activities | 698 |
| | 593 |
| | 1,155 |
| 25 |
| | 594 |
| | 698 |
|
Net Change in Cash and Cash Equivalents | (35 | ) | | (12 | ) | | — |
| 24 |
| | 126 |
| | (35 | ) |
Cash and Cash Equivalents at Beginning of Year | 133 |
| | 145 |
| | 145 |
| 224 |
| | 98 |
| | 133 |
|
Cash and Cash Equivalents at End of Year | $ | 98 |
| | $ | 133 |
| | $ | 145 |
| $ | 248 |
| | $ | 224 |
| | $ | 98 |
|
Supplemental Cash Flow Information: | | | | | | | | | | |
Cash paid (received) during the period for — | | | | | | | | | | |
Interest (net of $66, $69, and $54 capitalized, respectively) | $ | 45 |
| | $ | 7 |
| | $ | 20 |
| |
Interest (net of $29, $49, and $66 capitalized, respectively) | | $ | 65 |
| | $ | 50 |
| | $ | 45 |
|
Income taxes (net of refunds) | (33 | ) | | (379 | ) | | (134 | ) | (424 | ) | | (97 | ) | | (33 | ) |
Noncash transactions — | | | | | | | | | | |
Accrued property additions at year-end | 105 |
| | 114 |
| | 165 |
| 32 |
| | 78 |
| | 105 |
|
Capital lease obligation | — |
| | — |
| | 83 |
| |
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest
| 301 |
| | — |
| | — |
| — |
| | — |
| | 301 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Mississippi Power Company 20152017 Annual Report
| | Assets | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 98 |
| | $ | 133 |
| $ | 248 |
| | $ | 224 |
|
Receivables — | | | | | | |
Customer accounts receivable | 26 |
| | 43 |
| 36 |
| | 29 |
|
Unbilled revenues | 36 |
| | 35 |
| 41 |
| | 42 |
|
Income taxes receivable, current | | 4 |
| | 544 |
|
Affiliated | | 16 |
| | 15 |
|
Other accounts and notes receivable | 10 |
| | 11 |
| 12 |
| | 14 |
|
Affiliated companies | 20 |
| | 51 |
| |
Income taxes receivable, current | 20 |
| | — |
| |
Fossil fuel stock, at average cost | 104 |
| | 100 |
| |
Materials and supplies, at average cost | 75 |
| | 62 |
| |
Fossil fuel stock | | 17 |
| | 100 |
|
Materials and supplies, current | | 44 |
| | 76 |
|
Other regulatory assets, current | 95 |
| | 73 |
| 125 |
| | 115 |
|
Prepaid income taxes | 39 |
| | 70 |
| |
Other current assets | 8 |
| | 5 |
| 9 |
| | 8 |
|
Total current assets | 531 |
| | 583 |
| 552 |
| | 1,167 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 4,886 |
| | 4,378 |
| 4,773 |
| | 4,865 |
|
Less accumulated provision for depreciation | 1,262 |
| | 1,173 |
| |
Less: Accumulated provision for depreciation | | 1,325 |
| | 1,289 |
|
Plant in service, net of depreciation | 3,624 |
| | 3,205 |
| 3,448 |
| | 3,576 |
|
Construction work in progress | 2,254 |
| | 2,161 |
| 84 |
| | 2,545 |
|
Total property, plant, and equipment | 5,878 |
| | 5,366 |
| 3,532 |
| | 6,121 |
|
Other Property and Investments | 11 |
| | 5 |
| 30 |
| | 12 |
|
Deferred Charges and Other Assets: | | | | | | |
Deferred charges related to income taxes | 290 |
| | 226 |
| 35 |
| | 361 |
|
Other regulatory assets, deferred | 525 |
| | 385 |
| 437 |
| | 518 |
|
Income taxes receivable, non-current | 544 |
| | — |
| |
Accumulated deferred income taxes | — |
| | 33 |
| 247 |
| | — |
|
Other deferred charges and assets | 61 |
| | 44 |
| 33 |
| | 56 |
|
Total deferred charges and other assets | 1,420 |
| | 688 |
| 752 |
| | 935 |
|
Total Assets | $ | 7,840 |
| | $ | 6,642 |
| $ | 4,866 |
| | $ | 8,235 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 20152017 and 20142016
Mississippi Power Company 20152017 Annual Report
| | Liabilities and Stockholder's Equity | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Current Liabilities: | | | | | | |
Securities due within one year | $ | 728 |
| | $ | 778 |
| |
Securities due within one year — | | | | |
Parent | | $ | — |
| | $ | 551 |
|
Other | | 989 |
| | 78 |
|
Notes payable | 500 |
| | — |
| 4 |
| | 23 |
|
Interest-bearing refundable deposits | — |
| | 275 |
| |
Accounts payable — | | | | | | |
Affiliated | 85 |
| | 86 |
| 59 |
| | 62 |
|
Other | 135 |
| | 178 |
| 96 |
| | 135 |
|
Customer deposits | 16 |
| | 15 |
| |
Accrued taxes — | | | | | | |
Accrued income taxes | — |
| | 142 |
| 40 |
| | — |
|
Other accrued taxes | 85 |
| | 84 |
| 101 |
| | 99 |
|
Unrecognized tax benefits | | — |
| | 383 |
|
Accrued interest | 18 |
| | 76 |
| 16 |
| | 46 |
|
Accrued compensation | 26 |
| | 26 |
| 39 |
| | 42 |
|
Asset retirement obligations, current | | 37 |
| | 32 |
|
Over recovered regulatory clause liabilities | 96 |
| | 1 |
| — |
| | 51 |
|
Mirror CWIP | — |
| | 271 |
| |
Customer liability associated with Kemper refunds | 73 |
| | — |
| |
Other current liabilities | 74 |
| | 46 |
| 82 |
| | 36 |
|
Total current liabilities | 1,836 |
| | 1,978 |
| 1,463 |
| | 1,538 |
|
Long-Term Debt (See accompanying statements) | 1,886 |
| | 1,621 |
| 1,097 |
| | 2,424 |
|
Deferred Credits and Other Liabilities: | | | | | | |
Accumulated deferred income taxes | 762 |
| | 180 |
| — |
| | 756 |
|
Deferred credits related to income taxes | 8 |
| | 9 |
| 372 |
| | 7 |
|
Accumulated deferred investment tax credits | 5 |
| | 283 |
| |
Employee benefit obligations | 153 |
| | 148 |
| 116 |
| | 115 |
|
Asset retirement obligations | 154 |
| | 48 |
| |
Unrecognized tax benefits | 368 |
| | 2 |
| |
Asset retirement obligations, deferred | | 137 |
| | 146 |
|
Other cost of removal obligations | 165 |
| | 166 |
| 178 |
| | 170 |
|
Other regulatory liabilities, deferred | 71 |
| | 64 |
| 79 |
| | 77 |
|
Other deferred credits and liabilities | 40 |
| | 26 |
| 33 |
| | 26 |
|
Total deferred credits and other liabilities | 1,726 |
| | 926 |
| 915 |
| | 1,297 |
|
Total Liabilities | 5,448 |
| | 4,525 |
| 3,475 |
| | 5,259 |
|
Cumulative Redeemable Preferred Stock (See accompanying statements) | 33 |
| | 33 |
| 33 |
| | 33 |
|
Common Stockholder's Equity (See accompanying statements) | 2,359 |
| | 2,084 |
| 1,358 |
| | 2,943 |
|
Total Liabilities and Stockholder's Equity | $ | 7,840 |
| | $ | 6,642 |
| $ | 4,866 |
| | $ | 8,235 |
|
Commitments and Contingent Matters (See notes) |
| |
|
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 20152017 and 20142016
Mississippi Power Company 20152017 Annual Report
| | | 2015 | | 2014 | | 2015 | | 2014 | 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) | | (percent of total) | (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | | | | | | | | |
Long-term notes payable — | | | | | | | | | | | | | | |
2.35% due 2016 | $ | 300 |
| | $ | 300 |
| | | | | |
5.60% due 2017 | 35 |
| | 35 |
| | | | | $ | — |
| | $ | 35 |
| | | | |
1.63% due 2018 | | 50 |
| | 50 |
| | | | |
5.55% due 2019 | 125 |
| | 125 |
| | | | | 125 |
| | 125 |
| | | | |
1.63% to 5.40% due 2035-2042 | 680 |
| | 680 |
| | | | | |
Adjustable rates (1.84% to 1.90% at 1/1/16) due 2016 | 425 |
| | 775 |
| | | | | |
4.25% to 5.40% due 2035-2042 | | 630 |
| | 630 |
| | | | |
Adjustable rate (3.05% at 12/31/17) due 2018 | | 900 |
| | 1,200 |
| | | | |
Total long-term notes payable | 1,565 |
| | 1,915 |
| | | | | 1,705 |
| | 2,040 |
| | | | |
Other long-term debt — | | | | | | | | | | | | | | |
Pollution control revenue bonds — | | | | | | | | | | | | | | |
5.15% due 2028 | 43 |
| | 43 |
| | | | | 43 |
| | 43 |
| | | | |
Variable rate (0.16% at 1/1/16) due 2020 | 7 |
| | 7 |
| | | | | |
Variable rates (0.10% to 0.11% at 1/1/16) due 2025-2028 | 33 |
| | 33 |
| | | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | | 40 |
| | 40 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | 270 |
| | 270 |
| | | | | 270 |
| | 270 |
| | | | |
Long-term debt payable to parent company (1.49% to 1.74%) due 2017 | 576 |
| | — |
| | | | | |
Long-term debt payable to parent company (2.27%) due 2017 | | — |
| | 551 |
| | | | |
Total other long-term debt | 929 |
| | 353 |
| | | | | 353 |
| | 904 |
| | | | |
Capitalized lease obligations | 77 |
| | 79 |
| | | | | — |
| | 74 |
| | | | |
Unamortized debt premium | 53 |
| | 63 |
| | | | | 36 |
| | 45 |
| | | | |
Unamortized debt discount | (2 | ) | | (2 | ) | | | | | (1 | ) | | (2 | ) | | | | |
Unamortized debt issuance expense | (8 | ) | | (9 | ) | | | | | (7 | ) | | (8 | ) | | | | |
Total long-term debt (annual interest requirement — $87 million) | 2,614 |
| | 2,399 |
| | | | | |
Total long-term debt (annual interest requirement — $86 million) | | 2,086 |
| | 3,053 |
| | | | |
Less amount due within one year | 728 |
| | 778 |
| | | | | 989 |
| | 629 |
| | | | |
Long-term debt excluding amount due within one year | 1,886 |
| | 1,621 |
| | 44.1 | % | | 43.3 | % | 1,097 |
| | 2,424 |
| | 44.1 | % | | 44.9 | % |
Cumulative Redeemable Preferred Stock: | | | | | | | | | | | | | | |
$100 par value — | | | | | | | | | | | | | | |
Authorized — 1,244,139 shares | | | | | | | | | | | | | | |
Outstanding — 334,210 shares | | | | | | | | | | | | | | |
4.40% to 5.25% (annual dividend requirement — $2 million) | 33 |
| | 33 |
| | 0.8 |
| | 0.9 |
| 33 |
| | 33 |
| | 1.3 |
| | 0.6 |
|
Common Stockholder's Equity: | | | | | | | | | | | | | | |
Common stock, without par value — | | | | | | | | | | | | | | |
Authorized — 1,130,000 shares |
| |
| | | | |
| |
| | | | |
Outstanding — 1,121,000 shares | 38 |
| | 38 |
| | | | | 38 |
| | 38 |
| | | | |
Paid-in capital | 2,893 |
| | 2,612 |
| | | | | 4,529 |
| | 3,525 |
| | | | |
Accumulated deficit | (566 | ) | | (559 | ) | | | | | (3,205 | ) | | (616 | ) | | | | |
Accumulated other comprehensive loss | (6 | ) | | (7 | ) | | | | | (4 | ) | | (4 | ) | | | | |
Total common stockholder's equity | 2,359 |
| | 2,084 |
| | 55.1 |
| | 55.8 |
| 1,358 |
| | 2,943 |
| | 54.6 |
| | 54.5 |
|
Total Capitalization | $ | 4,278 |
| | $ | 3,738 |
| | 100.0 | % | | 100.0 | % | $ | 2,488 |
| | $ | 5,400 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 20152017, 20142016, and 20132015
Mississippi Power Company 20152017 Annual Report
| | | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income (Loss) | | Total | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) | (in millions) |
Balance at December 31, 2012 | 1 |
| | $ | 38 |
| | $ | 1,401 |
| | $ | 319 |
| | $ | (9 | ) | | $ | 1,749 |
| |
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (477 | ) | | — |
| | (477 | ) | |
Capital contributions from parent company | — |
| | — |
| | 976 |
| | — |
| | — |
| | 976 |
| |
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (72 | ) | | — |
| | (72 | ) | |
Balance at December 31, 2013 | 1 |
| | 38 |
| | 2,377 |
| | (230 | ) | | (8 | ) | | 2,177 |
| |
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (329 | ) | | — |
| | (329 | ) | |
Capital contributions from parent company | — |
| | — |
| | 235 |
| | — |
| | — |
| | 235 |
| |
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| |
Balance at December 31, 2014 | 1 |
| | 38 |
| | 2,612 |
| | (559 | ) | | (7 | ) | | 2,084 |
| 1 |
| | $ | 38 |
| | $ | 2,612 |
| | $ | (559 | ) | | $ | (7 | ) | | $ | 2,084 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
Capital contributions from parent company | — |
| | — |
| | 281 |
| | — |
| | — |
| | 281 |
| — |
| | — |
| | 281 |
| | — |
| | — |
| | 281 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2015 | 1 |
| | $ | 38 |
| | $ | 2,893 |
| | $ | (566 | ) | | $ | (6 | ) | | $ | 2,359 |
| 1 |
| | 38 |
| | 2,893 |
| | (566 | ) | | (6 | ) | | 2,359 |
|
Net loss after dividends on preferred stock | | — |
| | — |
| | — |
| | (50 | ) | | — |
| | (50 | ) |
Capital contributions from parent company | | — |
| | — |
| | 632 |
| | — |
| | — |
| | 632 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Balance at December 31, 2016 | | 1 |
| | 38 |
| | 3,525 |
| | (616 | ) | | (4 | ) | | 2,943 |
|
Net loss after dividends on preferred stock | | — |
| | — |
| | — |
| | (2,590 | ) | | — |
| | (2,590 | ) |
Capital contributions from parent company | | — |
| | — |
| | 1,004 |
| | — |
| | — |
| | 1,004 |
|
Other | | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2017 | | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,205 | ) | | $ | (4 | ) | | $ | 1,358 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 20152017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company (the Company) is a wholly ownedwholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, SouthernLINC Wireless,Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electricityelectric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC WirelessSouthern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cableoptics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers(ASC 606), revisesreplacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. The Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $9 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption of ASU 2015-03606 did not have an impact on the results of operations, cash flows, or financial condition of the Company. See Note 9 for disclosures impacted by ASU 2015-03.result in a cumulative-effect adjustment.
Leases
On May 1, 2015,In February 2016, the FASB issued ASU No. 2015-07,2016-02, Fair Value MeasurementLeases (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07),842) effective for fiscal years beginning after December 15, 2015. As permitted,(ASU 2016-02). ASU 2016-02 requires lessees to recognize on the Company elected to early adopt the guidance as of December 31, 2015balance sheet a lease liability and applied its provisions retrospectively to each prior period presented for comparative purposes. The amendments in ASU 2015-07 remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the neta right-of-use asset value per share practical expedient. In addition, the amendments remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value usingleases. ASU 2016-02 also changes the net asset value per share practical expedient regardless of whether the practical expedient was used. In accordance with ASU 2015-07, previously reported amounts have been conformed to the current presentation. The adoption of ASU 2015-07 had no impact on the results of operations, cash flows, or financial condition of the Company. See Note 2 for disclosures impacted by ASU 2015-07.
On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes (ASU 2015-17), which simplifies therecognition, measurement, and presentation of deferred income taxes. ASU 2015-17 requires deferred tax assetsexpense associated with leases and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted,provides clarification regarding the Company elected to early adopt the guidance asidentification of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-current accumulated deferred income taxes and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet.certain
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
Other thancomponents of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the reclassification,Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2015-172016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have ana material impact on the results of operations, financial position, or cash flows or financial condition of the Company. See NoteNotes 5 and 8 for disclosures impacted by ASU 2015-17.2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $140 million, $231 million, and $295 million $259 million,during 2017, 2016, and $205 million during 2015, 2014, and 2013, respectively. Cost allocation methodologies used by SCS prior to the repealrepeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. See Note 7 under "Operating Leases" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene CountyCounty Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $11$9 million, $13 million, and $13$11 million in 2015, 2014,2017, 2016, and 2013,2015, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, whichfacility. There were no fuel purchases in 2017 or 2016. Fuel purchases were $8 million $34 million, and $27 million in 2015, 2014, and 2013, respectively.2015. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, whichwhich totaled $31 million, $26 million, and $27 million $31 million,in 2017, 2016, and $17 million in 2015, 2014, and 2013, respectively. See Note 4 for additional information.
Total power purchased from affiliates through the power pool, included in purchased power in the statement of operations, totaled $16 million, $29 million, and $7 million in 2017, 2016, and 2015, respectively.
In June 2017, the Company received a capital contribution from Southern Company of $1.0 billion. The Company used a portion of the proceeds to repay all of the $591 million outstanding principal amount of promissory notes to Southern Company. See Note 6 for additional information.
On September 15, 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible research and experimental (R&E) expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" for additional information.
The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein,herein, the Company neither provided nor received any material services to or from affiliates in 2015, 2014,2017, 2016, or 2013.2015.
The traditional electric operating companies, including the Company, and SouthernSouthern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities
The Company is subject to the provisions of the FASB in accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
| | | 2015 |
| | 2014 |
| | Note | 2017 |
| | 2016 |
| | Note |
| (in millions) | (in millions) |
Retiree benefit plans – regulatory assets | $ | 163 |
| | $ | 169 |
| | (a,g) | $ | 174 |
| | $ | 173 |
| | (a) |
Property damage | (64 | ) | | (62 | ) | | (i) | |
Deferred income tax charges | 291 |
| | 227 |
| | (c) | |
Asset retirement obligations | | 95 |
| | 83 |
| | (b) |
Kemper County energy facility | | 88 |
| | 194 |
| | (c) |
Remaining net book value of retired assets | 36 |
| | 2 |
| | (b) | 44 |
| | 53 |
| | (d) |
Property tax | 27 |
| | 28 |
| | (d) | 43 |
| | 37 |
| | (e) |
Vacation pay | 11 |
| | 11 |
| | (e,g) | |
Plant Daniel Units 3 and 4 regulatory assets | 29 |
| | 23 |
| | (j) | |
Deferred charges related to income taxes | | 36 |
| | 362 |
| | (d) |
Plant Daniel Units 3 and 4 | | 36 |
| | 33 |
| | (f) |
Other regulatory assets | 16 |
| | 18 |
| | (b) | 28 |
| | 28 |
| | (g) |
Fuel-hedging (realized and unrealized) losses | 50 |
| | 47 |
| | (f,g) | |
Asset retirement obligations | 70 |
| | 11 |
| | (c) | |
ECO carryforward | | 26 |
| | 22 |
| | (h) |
Other regulatory liabilities | | — |
| | (1 | ) | | (i) |
Deferred credits related to income taxes | | (377 | ) | | (9 | ) | | (j) |
Other cost of removal obligations | (167 | ) | | (166 | ) | | (c) | (178 | ) | | (170 | ) | | (k) |
Kemper IGCC regulatory assets | 216 |
| | 148 |
| | (h) | |
Mirror CWIP | — |
| | (271 | ) | | (h) | |
Other regulatory liabilities | (11 | ) | | (13 | ) | | (b) | |
Property damage | | (57 | ) | | (68 | ) | | (l) |
Total regulatory assets (liabilities), net | $ | 667 |
| | $ | 172 |
| | $ | (42 | ) | | $ | 737 |
| |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 1415 years. See Note 2 for additional information. |
| |
(b) | Recorded andTo be recovered or amortized asupon completion of removal activities over a period approved by the Mississippi PSC. |
| |
(c) | Asset retirement and removalIncludes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities.six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." |
| |
(d) | Recovered over the related property lives up to 48 years. |
| |
(e) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginningbeginning in April of the following year. See Note 3 under "Ad"Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. |
| |
(e) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. |
| |
(f) | Fuel-hedgingRepresents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10-year period beginning October 2021. |
| |
(g) | Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. |
| |
(g) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."Recovered through the ECO clause in the year following the deferral. |
| |
(i) | Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. |
| |
(j) | This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million, of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million, of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight-year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. |
| |
(k) | Collected in advance from customers to remove assets upon their retirement. |
| |
(l) | For additional information, see Note 1 under "Provision for Property Damage." |
| |
(j) | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle""Kemper County Energy Facility" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Government Grants
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper IGCCCounty energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE(Initial DOE Grants). Through December 31, 2015,2017, the Company has received grant funds of $382 million, of which $245 million of the Initial DOE Grants were used for the construction of the Kemper IGCC,County energy facility, which is reflected in the Company's financial statements as a reduction to the Kemper IGCCCounty energy facility capital costs.costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $25$2 million is expected to be received for its initial operation.allowable costs through December 31, 2017. See Note 3 under "Kemper IGCC"Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Revenues
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually.
The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.0% represented 19.3% of the Company's total operating revenues in 20152017 and are largely subject to rolling 10-year cancellationcancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Except as described above for the collection of the Company’sCompany's cost-based MRA electric tariff customers, the Company has a diversified base of customers. Nocustomers and no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
See Note 3 under "Retail Regulatory Matters" for additional information.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. TaxesTaxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company's property, plant, and equipment in service consisted of the following at December 31:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Generation | $ | 2,723 |
| | $ | 2,293 |
| $ | 2,801 |
| | $ | 2,632 |
|
Transmission | 688 |
| | 665 |
| 737 |
| | 712 |
|
Distribution | 891 |
| | 854 |
| 946 |
| | 916 |
|
General | 503 |
| | 485 |
| 204 |
| | 520 |
|
Plant acquisition adjustment | 81 |
| | 81 |
| 85 |
| | 85 |
|
Total plant in service | $ | 4,886 |
| | $ | 4,378 |
| $ | 4,773 |
| | $ | 4,865 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for all costs associated with operating and maintaining the Kemper IGCC assets already placed in service and a portion of the railway track maintenance
NOTES (continued)
Mississippi Power Company 2015 Annual Report
costs. The portion of railway track maintenance costs not charged to operationoperations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause. Through second quarter 2015, all costs associated with the combined cycle and the associated common facilities portion of the Kemper IGCC, excluding the lignite mine, were deferred to a regulatory asset to be recovered over the life of the Kemper IGCC. Beginning in the third quarter 2015, the Company began expensing a portion of these ongoing cost previously deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information.
Depreciation, Depletion, and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.7% in 2017, 4.2% in 2016, and 4.7% in 2015, 3.3%2015. The decrease in 2014, and 3.4%2017 is primarily due to lower depreciation expense as a result of recording a loss on the lignite mine in 2013.June 2017. The increasedecrease in the 20152016 depreciation rate is primarily due to an asset retirement obligation (ARO)fully depreciating and retiring the ARO at Plant Watson, incurred aspartially offset by the increase in depreciation for the Plant Daniel scrubbers for a result of changes in environmental regulations.full year. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. On December 3, 2015, theThe Mississippi PSC approved the 2014 study, filed in 2014, with new rates effective January 1, 2015. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities.
The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent tofacilities, except for the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights is recognized and charged to fuel stock and is expected to be recovered through the Company’s fuel clause. Through the second quarter 2015, depreciation associated with theCounty energy facility combined cycle and the associated common facilities portion of the Kemper IGCC was deferred as a regulatory asset to be recovered over the life of the Kemper IGCC. Beginningrelated assets in the third quarter 2015, the Company began expensing certain ongoing project costs, including depreciation, that previously were deferred as regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" for additional information.service.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA on April 17,in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in thethe statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as eithereither a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
Details of the AROs included in the balance sheets are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Balance at beginning of year | $ | 48 |
| | $ | 42 |
| $ | 179 |
| | $ | 177 |
|
Liabilities incurred | 101 |
| | — |
| — |
| | 15 |
|
Liabilities settled | (3 | ) | | (3 | ) | (23 | ) | | (23 | ) |
Accretion | 4 |
| | 2 |
| 5 |
| | 5 |
|
Cash flow revisions | 27 |
| | 7 |
| 13 |
| | 5 |
|
Balance at end of year | $ | 177 |
| | $ | 48 |
| $ | 174 |
| | $ | 179 |
|
The increase in liabilities incurred and cash flow revisions in 20152017 is primarily relaterelated to an increasea revision in AROs associated with facilities impacted by the CCR Rule located at Plant Watson and Plant Greene County. closure date of the lignite mine ARO.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 20152017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure in place.closure. As further analysis is performed including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life,closure details are developed, the Company expects towill continue to periodically update these estimates.
The increase in cash flow revisions in 2014 related to the Company's AROs associated with the Plant Watson landfill and Plant Greene County asbestos.cost estimates as necessary.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, theThe Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 5.99%6.7%, 6.91%6.5%, and 6.89%5.99% for the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, respectively. AFUDC equity was $72 million, $124 million, and $110 million $136 million,in 2017, 2016, and $122 million2015, respectively. The decrease in 2015, 2014, and 2013, respectively.2017 resulted from the Kemper IGCC project suspension in June 2017.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.
Provision for Property DamageMunicipal and Rural Associations Tariff
The Company carries insurance forprovides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the costCity of certain types of damage to generation plants and general property. However,Collins, all located in southeastern Mississippi, under a long-term cost-based, FERC regulated MRA tariff.
In March 2016, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage toreached a settlement agreement with its property, including transmission and distribution facilities. As permittedwholesale customers, which was subsequently approved by the Mississippi PSC andFERC, for an increase in wholesale base revenues under the FERC, the Company accrues for the costMRA cost-based electric tariff, primarily as a result of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retailplacing
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
property damage reserve. In eachscrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of 2015, 2014,$7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and 2013,other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income.
The Company expects to make a subsequent MRA filing during the second quarter 2018. The filing is intended to be consistent with the February 6, 2018 Mississippi PSC order for cost recovery of the Kemper County energy facility, including the impact of Tax Reform Legislation. The ultimate outcome of this matter cannot be determined at this time.
On September 18, 2017, the Company made retail accruals of $3 million. The Company accrued $0.3 million annually in 2015, 2014, and 2013 for the wholesale jurisdiction. As of December 31, 2015, the property damage reserve balances were $63 million and $1 million for retail and wholesale, respectively.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized.
Fuel Inventory
Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates or capitalizedCooperative Energy executed a Shared Service Agreement (SSA), as part of the Kemper IGCC costs if used for testing.MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The retail rate is approvedSSA accepted by the Mississippi PSCFERC on October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instrumentsoption to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially alldecrease its use of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from the fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted forgeneration services under the accrual method. FuelMRA tariff, subject to annual and interest rate derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable throughcumulative caps and a one-year notice requirement. In the Mississippi PSC approved fuel-hedging program as discussed below resultevent Cooperative Energy elects to reduce these services, the related reduction in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these wouldCompany's revenues is not expected to be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts that qualify as fair value hedges are marked to marketsignificant through current period income and are recorded on a net basis in the statements of operations. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives.2020.
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2015.Fuel Cost Recovery
The Company has an ECMa wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. Effective January 1, 2018, the wholesale MRA fuel rate increased $11 million annually. At December 31, 2017, over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million, which is included in over-recovered regulatory clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changesliabilities, current in the fair value of these financial instrumentsbalance sheets.
The Company's operating revenues are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified asadjusted for differences in actual recoverable fuel expensecost and are includedamounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the ECMbilling factor applied to customer billings. Theshould have no significant effect on the Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.revenues or net income, but will affect cash flow.
Market-Based Rate Authority
The Company is exposedhas authority from the FERC to losses relatedsell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to financial instrumentsbe tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the event of counterparties' nonperformance. The Company has established controls to determineenergy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and monitor the creditworthiness of counterparties in order toSouthern Power's existing tailored mitigation may not effectively mitigate the Company's exposurepotential to counterparty credit risk.exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
Comprehensive Income
The objectiveIn December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic eventscost-based price caps for certain sales outside of the period other than transactions with owners. Comprehensive income consistsenergy auction, finding that all of net income,these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the fair valuetraditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Variable Interest EntitiesOn October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The primary beneficiaryultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Power Supply Agreement
In 2008, the Company entered into a VIE is required10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to consolidate86 MWs. On February 5, 2018, the VIE when itCompany and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs.
Cooperative Energy also has botha 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the power to direct the activitiesCompany's transmission system that became effective in 2011. As a result of the VIE that most significantly impactPSA amendments, Cooperative Energy and SCS amended the VIE's economic performanceterms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
General
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company is required to provide financing for all costs associatedof compliance with the mine developmentenvironmental laws and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the constructionregulations. Costs not addressed through one of the Kemper IGCC. Liberty Fuels qualifies as a VIE for whichspecific cost recovery clauses are expected to be recovered through the Company is the primary beneficiary. For the year ended December 31, 2015, the VIE consolidation resulted in an ARO asset and associated liability in the amounts of $21 million and $25 million, respectively. For the year ended December 31, 2014, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21 million and $24 million, respectively. For the year ended December 31, 2013, the VIE consolidation resulted in an ARO and associated liability in the amounts of $21 million and $23 million, respectively.Company's base rates. See Note 3 to the financial statements under "Integrated Coal Gasification Combined Cycle""Retail Regulatory Matters" and "Kemper County Energy Facility" for additional information.
2. RETIREMENT BENEFITSIn 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi.
In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.
On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC.
The ultimate outcome of these matters cannot be determined at this time.
Performance Evaluation Plan
The Company hasCompany's retail base rates are set under the PEP, a defined benefit, trusteed, pensionrate plan covering substantially all employees. This qualified pension planapproved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is funded in accordance with requirementstypically filed prior to the beginning of the Employee Retirement Income Security Actyear based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of 1974, as amended (ERISA). No contributionsthe year and allows for review of the actual revenue requirement compared to the qualified pension plan were madeprojected filing.
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the year ended December 31, 2015, and no mandatory contributionsMPUS disputed certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to the qualified pension plan are anticipated for2010 PEP lookback filing, which remain under review, also impact the year ending December 31, 2016. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2016, no other postretirement trust contributions are expected.2012 PEP lookback filing.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Actuarial AssumptionsIn 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.
In 2014, 2015, 2016, and 2017, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the Company submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.
On February 7, 2018, the Company revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
The weighted averageultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were extended by an order issued by the Mississippi PSC in July 2016, until the time the Mississippi PSC approves a comprehensive portfolio plan program. The ultimate outcome of this matter cannot be determined at this time.
On July 6, 2017, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider 2017 compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
On November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing, which included a small decrease in annual retail revenues. The ultimate outcome of this matter cannot be determined at this time.
See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Environmental Compliance Overview Plan
In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club under which, among other things, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018 (and the units were retired in July 2016). The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively).
In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with Plant Watson and Plant Greene County, respectively, for amortization over five-year periods that began in July 2016 and July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements.
In August 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates assumedbecame effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the actuarial calculations used2017 filing, along with related carrying costs.
On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to determine both the net periodic costscarryforward from the prior year. The rates became effective with the first billing cycle for the pension and other postretirement benefit plans for the following year and the benefit obligations asJune 2017. Approximately $26 million of related revenue requirements in excess of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2015 | | 2014 | | 2013 |
Pension plans | | | | | |
Discount rate – interest costs | 4.17 | % | | 5.01 | % | | 4.26 | % |
Discount rate – service costs | 4.49 |
| | 5.01 |
| | 4.26 |
|
Expected long-term return on plan assets | 8.20 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – interest costs | 4.03 | % | | 4.85 | % | | 4.04 | % |
Discount rate – service costs | 4.38 |
| | 4.85 |
| | 4.04 |
|
Expected long-term return on plan assets | 7.23 |
| | 7.30 |
| | 7.04 |
|
Annual salary increase | 3.59 |
| | 3.59 |
| | 3.59 |
|
|
| | | | | |
Assumptions used to determine benefit obligations: | 2015 | | 2014 |
Pension plans | | | |
Discount rate | 4.69 | % | | 4.17 | % |
Annual salary increase | 4.46 |
| | 3.59 |
|
Other postretirement benefit plans | | | |
Discount rate | 4.47 | % | | 4.03 | % |
Annual salary increase | 4.46 |
| | 3.59 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
For purposes of its December 31, 2015 measurement date, the Company adopted new mortality tables2% maximum was deferred for its pension and other postretirement benefit plans, which reflect decreased life expectanciesinclusion in the U.S. The adoption of new mortality tables reduced the projected benefit obligations for the Company's pension and other postretirement benefit plans by approximately $9 million and $2 million, respectively.2018 filing, along with related carrying costs.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
An additional assumption used in measuringOn February 14, 2018, the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuringCompany submitted its ECO plan filing for 2018, including the APBO aseffects of December 31, 2015 were as follows:
|
| | | | | | | | |
| | Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | | 6.50 | % | | 4.50 | % | | 2024 |
Post-65 medical | | 5.50 |
| | 4.50 |
| | 2024 |
Post-65 prescription | | 10.00 |
| | 4.50 |
| | 2025 |
AnTax Reform Legislation, which requested the maximum 2% annual increase in revenues, or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2015 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 5 |
| | $ | (5 | ) |
Service and interest costs | — |
| | — |
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $447approximately $17 million, at December 31, 2015 and $462 million at December 31, 2014. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 513 |
| | $ | 409 |
|
Service cost | 13 |
| | 10 |
|
Interest cost | 21 |
| | 20 |
|
Benefits paid | (22 | ) | | (17 | ) |
Actuarial loss (gain) | (25 | ) | | 91 |
|
Balance at end of year | 500 |
| | 513 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 446 |
| | 387 |
|
Actual return on plan assets | 4 |
| | 40 |
|
Employer contributions | 2 |
| | 36 |
|
Benefits paid | (22 | ) | | (17 | ) |
Fair value of plan assets at end of year | 430 |
| | 446 |
|
Accrued liability | $ | (70 | ) | | $ | (67 | ) |
At December 31, 2015, the projected benefit obligations for the qualified and non-qualified pension plans were $470 million and $30 million, respectively. All pension plan assets areprimarily related to the qualified pension plan.carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
II-416The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which resulted in an annual revenue increase of approximately $55 million. On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2017, the amount of under-recovered retail fuel costs included in the balance sheet in customer accounts receivable was approximately $6 million compared to $37 million over recovered at December 31, 2016.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Ad Valorem Tax Adjustment
The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
System Restoration Rider
In February 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million. These filings were suspended by the Mississippi PSC for review.
On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million. A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing.
On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018.
The ultimate outcome of these matters cannot be determined at this time. See Note 1 to the financial statements under "Provision for Property Damage" for additional information.
Storm Damage Cost Recovery
In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded.
Kemper County Energy Facility
Overview
The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, the Company constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Amounts recognizedSchedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the balance sheets2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion in Cost Cap Exceptions. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future.
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, the Company had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at December 31, 2015approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and 2014gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Company's pension plans consistKemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the following:Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 144 |
| | $ | 151 |
|
Other current liabilities | (3 | ) | | (2 | ) |
Employee benefit obligations | (67 | ) | | (65 | ) |
Presented below areUnder the amounts included in regulatory assets at December 31, 2015Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and 2014 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost alonginclude no recovery for costs associated with the estimated amortizationgasifier portion of such amounts for 2016.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | Estimated Amortization in 2016 |
| (in millions) |
Prior service cost | $ | 2 |
| | $ | 3 |
| | $ | 1 |
|
Net loss | 142 |
| | 148 |
| | 7 |
|
Regulatory assets | $ | 144 |
| | $ | 151 |
| | |
The changesthe Kemper County energy facility in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2015 and 2014 are presented in the following table:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Regulatory assets: | | | |
Beginning balance | $ | 151 |
| | $ | 78 |
|
Net (gain) loss | 4 |
| | 79 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (1 | ) |
Amortization of net gain (loss) | (10 | ) | | (5 | ) |
Total reclassification adjustments | (11 | ) | | (6 | ) |
Total change | (7 | ) | | 73 |
|
Ending balance | $ | 144 |
| | $ | 151 |
|
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Service cost | $ | 13 |
| | $ | 10 |
| | $ | 11 |
|
Interest cost | 21 |
| | 20 |
| | 18 |
|
Expected return on plan assets | (33 | ) | | (29 | ) | | (27 | ) |
Recognized net loss | 10 |
| | 5 |
| | 10 |
|
Net amortization | 1 |
| | 1 |
| | 1 |
|
Net periodic pension cost | $ | 12 |
| | $ | 7 |
| | $ | 13 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets,2018 or at any future date. On February 12, 2018, the Company has elected to amortize changes inmade the market value of all plan assets over five years rather than recognizerequired compliance filing with the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.Mississippi PSC. The Kemper
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Future benefit payments reflect expectedSettlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) the Company to file a reserve margin plan with the Mississippi PSC by August 2018.
As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the Company's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.
In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and are estimated based on assumptions usedconsulting and legal fees over periods ranging from two years to measure10 years. On July 6, 2017, the projected benefit obligation forMississippi PSC issued an order requiring the pension plans. At December 31, 2015, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2016 | $ | 20 |
|
2017 | 21 |
|
2018 | 22 |
|
2019 | 24 |
|
2020 | 25 |
|
2021 to 2025 | 146 |
|
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2015 and 2014 were as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 96 |
| | $ | 81 |
|
Service cost | 1 |
| | 1 |
|
Interest cost | 4 |
| | 4 |
|
Benefits paid | (5 | ) | | (5 | ) |
Actuarial loss (gain) | (1 | ) | | 14 |
|
Plan amendment | 1 |
| | — |
|
Retiree drug subsidy | 1 |
| | 1 |
|
Balance at end of year | 97 |
| | 96 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 24 |
| | 23 |
|
Actual return on plan assets | — |
| | 2 |
|
Employer contributions | 3 |
| | 3 |
|
Benefits paid | (4 | ) | | (4 | ) |
Fair value of plan assets at end of year | 23 |
| | 24 |
|
Accrued liability | $ | (74 | ) | | $ | (72 | ) |
Amounts recognized in the balance sheets at December 31, 2015 and 2014Company to establish a regulatory liability account to maintain current rates related to the Company's other postretirement benefit plans consistKemper County energy facility following the July 2017 completion of the following:amortization period for certain of these regulatory assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
Lignite Mine and CO2 Pipeline Facilities
The Company owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013. |
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Other regulatory assets, deferred | $ | 21 |
| | $ | 18 |
|
Other regulatory liabilities, deferred | (3 | ) | | (2 | ) |
Employee benefit obligations | (74 | ) | | (72 | ) |
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.
In addition, the Company constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO2. Denbury has the right to terminate the contract at any time because the Company did not place the Kemper IGCC in service by July 1, 2017.
II-418The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and the Company and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. The Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
could have a material impact on the Company's results of operations, financial condition, and liquidity. The Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
Presented below areOn June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against the amounts includedCompany, Southern Company, and SCS in net regulatory assets (liabilities) at December 31, 2015 and 2014the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of the Company, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, the Company, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, the Company reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other postretirement benefit plans that hadthings, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
Regulated utility businesses can continue deducting all business interest expense and are not yet been recognizedeligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, net periodic other postretirement benefit cost alongoperating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $372 million and a $375 million increase in regulatory liabilities as of December 31, 2017, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Mississippi PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the estimated amortizationFERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the Company's rate filings to reflect the impacts of such amountsthe Tax Reform Legislation.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for 2016.additional information.
The ultimate outcome of these matters cannot be determined at this time. |
| | | | | | | | | | | |
| 2015 | | 2014 | | Estimated Amortization in 2016 |
| (in millions) |
Prior service cost | $ | — |
| | $ | (2 | ) | | $ | — |
|
Net (gain) loss | (18 | ) | | 18 |
| | 1 |
|
Net regulatory assets | $ | (18 | ) | | $ | 16 |
| | |
Bonus DepreciationUnder the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The changesPATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, approximately $50 million of positive cash flows is expected to result from bonus depreciation for the balance2017 tax year and approximately $10 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of net regulatory assets (liabilities)these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the other postretirement benefit plansKemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes," respectively, for the plan years ended December 31, 2015 and 2014 are presented in the following table:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Net regulatory assets (liabilities): | | | |
Beginning balance | $ | 16 |
| | $ | 2 |
|
Net (gain) loss | — |
| | 14 |
|
Change in prior service costs | 3 |
| | — |
|
Reclassification adjustments: | | | |
Amortization of net gain (loss) | (1 | ) | | — |
|
Total reclassification adjustments | (1 | ) | | — |
|
Total change | 2 |
| | 14 |
|
Ending balance | $ | 18 |
| | $ | 16 |
|
Componentsadditional information. The ultimate outcome of the other postretirement benefit plans' net periodic cost were as follows:these matters cannot be determined at this time.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Service cost | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 4 |
| | 4 |
| | 4 |
|
Expected return on plan assets | (2 | ) | | (2 | ) | | (1 | ) |
Net amortization | 1 |
| | — |
| | — |
|
Net periodic postretirement benefit cost | $ | 4 |
| | $ | 3 |
| | $ | 4 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2016 | $ | 6 |
| | $ | — |
| | $ | 6 |
|
2017 | 6 |
| | (1 | ) | | 5 |
|
2018 | 6 |
| | (1 | ) | | 5 |
|
2019 | 7 |
| | (1 | ) | | 6 |
|
2020 | 7 |
| | (1 | ) | | 6 |
|
2021 to 2025 | 36 |
| | (2 | ) | | 34 |
|
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
Benefit Plan Assets
Pension planSection 174 Research and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. TheExperimental Deduction
Southern Company, minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The compositionon behalf of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2015 and 2014, along with the targeted mix of assetsCompany, has reflected deductions for each plan, is presented below:
|
| | | | | | | | |
| Target | | 2015 | | 2014 |
Pension plan assets: | | | | | |
Domestic equity | 26 | % | | 30 | % | | 30 | % |
International equity | 25 |
| | 23 |
| | 23 |
|
Fixed income | 23 |
| | 23 |
| | 27 |
|
Special situations | 3 |
| | 2 |
| | 1 |
|
Real estate investments | 14 |
| | 16 |
| | 14 |
|
Private equity | 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | |
Domestic equity | 21 | % | | 24 | % | | 24 | % |
International equity | 20 |
| | 18 |
| | 19 |
|
Domestic fixed income | 38 |
| | 38 |
| | 41 |
|
Special situations | 3 |
| | 2 |
| | 1 |
|
Real estate investments | 11 |
| | 13 |
| | 11 |
|
Private equity | 7 |
| | 5 |
| | 4 |
|
Total | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assetsR&E expenditures related to the Company's qualified pension plan isKemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities,also include such deductions. In December 2016, Southern Company and the assumed growth in assets and liabilities. BecauseIRS reached a significant portionproposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation,this approval, the Company employs a formal rebalancing program. As additional risk management, external investment managersrecognized $176 million of previously unrecognized tax benefits and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.reversed $36 million of associated accrued interest.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2015 and 2014. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments and private equity.Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
The fair values of pension plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 76 |
| | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | 108 |
|
International equity* | 55 |
| | 46 |
| | — |
| | — |
| | 101 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
Mortgage- and asset-backed securities | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
Corporate bonds | — |
| | 53 |
| | — |
| | — |
| | 53 |
|
Pooled funds | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Cash equivalents and other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
Real estate investments | 14 |
| | — |
| | — |
| | 57 |
| | 71 |
|
Private equity | — |
| | — |
| | — |
| | 30 |
| | 30 |
|
Total | $ | 145 |
| | $ | 191 |
| | $ | — |
| | $ | 87 |
| | $ | 423 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Mississippi Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 78 |
| | $ | 32 |
| | $ | — |
| | $ | — |
| | $ | 110 |
|
International equity* | 49 |
| | 45 |
| | — |
| | — |
| | 94 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 32 |
| | — |
| | — |
| | 32 |
|
Mortgage- and asset-backed securities | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
Corporate bonds | — |
| | 53 |
| | — |
| | — |
| | 53 |
|
Pooled funds | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
Cash equivalents and other | — |
| | 30 |
| | — |
| | — |
| | 30 |
|
Real estate investments | 14 |
| | — |
| | — |
| | 51 |
| | 65 |
|
Private equity | — |
| | — |
| | — |
| | 26 |
| | 26 |
|
Total | $ | 141 |
| | $ | 225 |
| | $ | — |
| | $ | 77 |
| | $ | 443 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Mississippi Power Company 2015 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 2015 and 2014 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
International equity* | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Mortgage- and asset-backed securities | — |
| | — |
| | — |
| | — |
| | — |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 3 |
| | 4 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 7 |
| | $ | 12 |
| | $ | — |
| | $ | 4 |
| | $ | 23 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
NOTES (continued)
Mississippi Power Company 2015 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity* | $ | 3 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
International equity* | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Mortgage- and asset-backed securities | — |
| | — |
| | — |
| | — |
| | — |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 1 |
| | 1 |
| | — |
| | — |
| | 2 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 7 |
| | $ | 14 |
| | $ | — |
| | $ | 3 |
| | $ | 24 |
|
|
| |
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. |
Employee Savings PlanOther Matters
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made tois involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the plan for 2015, 2014, and 2013 were $5 million, $5 million, and $4 million, respectively.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, theThe Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Environmental MattersIn 2013, the Company submitted a claim under the Deep Horizon Economic and Property Damages Settlement Agreement associated with the oil spill that occurred in the Gulf of Mexico. The ultimate outcome of this matter cannot be determined at this time.
Environmental RemediationIn 2016, the SEC began conducting a formal investigation of Southern Company and the Company concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with no recommended enforcement action.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company mustprepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper County Energy Facility Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. The Company recorded total pre-tax charges to income related to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as the Company's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge of $78 million associated with the Kemper Settlement Agreement.
In the aggregate, since the Kemper County energy facility project started, the Company has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 11 to the financial statements for additional information on the individual charges by quarter.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and no longer represents a critical accounting estimate.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate Plans" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $4 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $2 million or less change in total annual benefit expense and a $25 million or less change in projected obligations.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.7%, 6.5%, and 5.99% for the years ended December 31, 2017, 2016, and 2015, respectively. The AFUDC rate is applied to CWIP consistent with jurisdictional regulatory treatment. AFUDC equity was $72 million, $124 million, and $110 million in 2017, 2016, and 2015, respectively. The decrease in 2017 resulted from the Kemper County energy facility project suspension in June 2017.
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview and Sources of Capital
Earnings for all periods presented were negatively affected by charges associated with the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" herein and Note 3 to the financial statements for additional information.
The Company's cash requirements primarily consist of funding ongoing operations, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms.
The Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company. Specifically, the Company has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide the Company with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. For additional information, see Note 6 to the financial statements under "Going Concern."
On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ended September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. government related to the settlement concerning deductible R&E expenditures. See Note 5 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.
As of December 31, 2017, the Company's current liabilities exceeded current assets by approximately $911 million primarily due to a $900 million unsecured term loan that matures on March 31, 2018. The Company expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. To fund the Company's capital needs over the next 12 months, the Company intends to utilize operating cash flows, external security issuances, lines of credit, bank term loans, equity contributions from Southern Company, and, to the extent necessary, loans from Southern Company.
The Company's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. The Company plans to obtain the funds required for construction and other purposes from operating cash flows, lines of credit,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
bank term loans, external security issuances, commercial paper, to the extent the Company is eligible to participate, and loans and/or equity contributions from Southern Company.
The Company's investments in the qualified pension plan increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated during 2018.
Net cash provided from operating activities totaled $503 million for 2017, an increase of $274 million as compared to 2016. The increase in cash provided from operating activities in 2017 was primarily due to tax refunds associated with the approval by the JCT of the Section 174 R&E settlement, largely offset by a decrease in income taxes related to the Kemper County energy facility and Tax Reform Legislation. Net cash provided from operating activities totaled $229 million for 2016, an increase of $56 million as compared to 2015. The increase in cash provided from operating activities in 2016 was primarily due to repayment in 2015 of ITCs relating to the Kemper County energy facility, as well as the 2015 mirror CWIP refund, partially offset by lower income tax benefits related to the Kemper County energy facility in 2016 and lower fuel rates in 2016.
Net cash used for investing activities in 2017, 2016, and 2015 totaled $504 million, $697 million, and $906 million, respectively. The cash used for investing activities in all years presented was primarily due to gross property additions related to the Kemper County energy facility. The cash used for investing activities in 2016 was partially offset by the receipt of Additional DOE Grants. The cash used for investing activities in 2015 also included gross property additions related to the Plant Daniel scrubber project.
Net cash provided from financing activities totaled $25 million in 2017 primarily due to capital contributions from Southern Company, largely offset by redemptions of long-term debt and short-term borrowings. Net cash provided from financing activities totaled $594 million in 2016 primarily due to long-term debt financings and capital contributions from Southern Company, partially offset by a decrease in short-term borrowings and redemptions of long-term debt. Net cash provided from financing activities totaled $698 million in 2015 primarily due to short-term borrowings, capital contributions from Southern Company, and long-term debt financings, partially offset by redemptions of long-term debt.
Significant balance sheet changes as of December 31, 2017 compared to 2016 include decreases of $2.5 billion in CWIP, a net change of $1.0 billion in accumulated deferred income taxes, an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year – other. Securities due within one year – parent decreased $551 million due to the repayment of promissory notes to Southern Company. Other significant balance sheet changes include $326 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the approval by the JCT of the Section 174 R&E settlement. The Company also had an increase of $365 million in deferred credits related to income taxes primarily resulting from the impacts of Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction," respectively, for additional information.
The Company's ratio of common equity to total capitalization plus short-term debt was 39% and 49% at December 31, 2017 and 2016, respectively. The decrease was due to Kemper IGCC losses. See Note 6 to the financial statements for additional information.
The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in raising capital. Any future financing through secured debt would also require approval by the Mississippi PSC.
The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
At December 31, 2017, the Company had approximately $248 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were $100 million, all of which is unused. In November 2017, the Company amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to the Company's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of December 31, 2017 was approximately $40 million. In addition, the Company had approximately $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode subsequent to December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Most of these bank credit arrangements, as well as the Company's term loan agreement, contain covenants that limit debt levels and typically contain cross acceleration to other indebtedness (including guarantee obligations) of the Company. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, the Company expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowing were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 4 |
| | 3.8 | % | | $ | 18 |
| | 3.0 | % | | $ | 36 |
|
December 31, 2016 | $ | 23 |
| | 2.6 | % | | $ | 112 |
| | 2.0 | % | | $ | 500 |
|
December 31, 2015 | $ | 500 |
| | 1.4 | % | | $ | 372 |
| | 1.3 | % | | $ | 515 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31. |
Financing Activities
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Bank Term Loans and Senior Notes
In March 2017, the Company issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In June 2017, the Company used a portion of the proceeds from Southern Company equity contributions to prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018, and to repay $10 million of the outstanding principal amount of bank loans. See "Parent Company Loans and Equity Contributions" herein for more information.
This unsecured term loan has covenants that limit debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes the long-term debt payable to affiliated trusts and other hybrid securities. In addition, this unsecured term loan contains cross-acceleration provisions to other debt (including guarantee obligations) that would be triggered if the Company defaulted on debt above a specified threshold, the payment of which was then accelerated. The Company is currently in compliance with all such covenants.
In August 2017, the Company repaid a $12.5 million short-term bank note.
In November 2017, the Company repaid at maturity $35 million aggregate principal amount of Series 2007A 5.60% Senior Notes.
Parent Company Loans and Equity Contributions
In February 2017, the Company amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note 5 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.
Credit Rating Risk
At December 31, 2017, the Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of the Company's credit rating to below investment grade by two of the three rating agencies.
There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At December 31, 2017, the maximum amount of potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $241 million.
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets, or at a minimum the cost at which it does so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of the Company to Ba1 from Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
On March 30, 2017, Fitch placed the ratings of the Company on rating watch negative.
On June 22, 2017, Moody's placed the ratings of the Company on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for the Company from under review to stable.
While it is unclear how the credit rating agencies, the FERC, and the Mississippi PSC may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, the Company may enter into derivatives that have been designated as hedges. The weighted average interest rate on $40 million of long-term variable interest rate exposure at December 31, 2017 was 2.49%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would have an immaterial effect on annualized interest expense at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (7 | ) | | $ | (47 | ) |
Contracts realized or settled | 8 |
| | 29 |
|
Current period changes(*) | (8 | ) | | 11 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (7 | ) | | $ | (7 | ) |
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, all of which are natural gas swaps, for the years ended December 31 were as follows:
|
| | | | | |
| 2017 | | 2016 |
| mmBtu Volume |
| (in millions) |
Total hedge volume | 53 |
| | 36 |
|
For natural gas hedges, the weighted average swap contract cost above market prices was approximately $0.14 per mmBtu as of December 31, 2017 and $0.19 per mmBtu as of December 31, 2016. The options outstanding were immaterial for the reporting periods presented. The costs associated with natural gas hedges are recovered through the Company's ECMs.
At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2017 were as follows:
|
| | | | | | | | | | | |
| Fair Value Measurements December 31, 2017 |
| Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 |
| (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (7 | ) | | (5 | ) | | (2 | ) |
Level 3 | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (7 | ) | | $ | (5 | ) | | $ | (2 | ) |
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements.
Capital Requirements and Contractual Obligations
Approximately $900 million will be required through December 31, 2018 to fund maturities of long-term debt. In addition, the Company has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode subsequent to December 31, 2017. See "Overview and Sources of Capital" herein for additional information.
The construction program of the Company is currently estimated to be $213 million for 2018, $199 million for 2019, $193 million for 2020, $167 million for 2021, and $118 million for 2022. These estimated program amounts also include capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $14 million, $16 million, $17 million, $13 million, and $3 million for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $23 million, $7 million, $7 million, $9 million, and $12 million for the years 2018, 2019, 2020, 2021, and 2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that covercosts related to capital expenditures will be fully recovered.
In addition, as discussed in Note 2 to the handlingfinancial statements, the Company provides postretirement benefits to substantially all employees and disposalfunds trusts to the extent required by the FERC.
Other funding requirements related to obligations associated with scheduled maturities of wastelong-term debt, as well as the related interest, derivative obligations, preferred stock dividends, unrecognized tax benefits, pension and releasesother post-retirement benefit plans, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 990 |
| | $ | 125 |
| | $ | 270 |
| | $ | 673 |
| | $ | 2,058 |
|
Interest | 86 |
| | 106 |
| | 79 |
| | 552 |
| | 823 |
|
Preferred stock dividends(b) | 2 |
| | 3 |
| | 3 |
| | — |
| | 8 |
|
Financial derivative obligations(c) | 6 |
| | 3 |
| | — |
| | — |
| | 9 |
|
Operating leases(d) | 3 |
| | 5 |
| | 4 |
| | 7 |
| | 19 |
|
Purchase commitments — | | | | | | | | | |
Capital(e) | 213 |
| | 379 |
| | 269 |
| | — |
| | 861 |
|
Fuel(f) | 280 |
| | 329 |
| | 191 |
| | 175 |
| | 975 |
|
Long-term service agreements(g) | 33 |
| | 75 |
| | 49 |
| | 245 |
| | 402 |
|
Purchased power(h) | 11 |
| | 29 |
| | 36 |
| | 454 |
| | 530 |
|
Pension and other postretirement benefits plans(i) | 7 |
| | 15 |
| | — |
| | — |
| | 22 |
|
Total | $ | 1,631 |
| | $ | 1,069 |
| | $ | 901 |
| | $ | 2,106 |
| | $ | 5,707 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to certain revenue bonds. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). For additional information, see Note 6 to the financial statements. |
| |
(b) | Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Derivative obligations are for energy-related derivatives. For additional information, see Notes 1 and 10 to the financial statements. |
| |
(d) | See Note 7 to the financial statements for additional information. |
| |
(e) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" for additional information. |
| |
(f) | Fuel commitments include coal and natural gas purchases, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(g) | Long-term service agreements include price escalation based on inflation indices. |
| |
(h) | Purchased power represents estimated minimum long-term commitments for the purchase of solar energy. Energy costs associated with solar PPAs are recovered through the fuel clause. See Notes 3 and 7 to the financial statements for additional information. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan and postretirement benefit plans contributions, financing activities, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may also incur substantialbe taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to clean up affected sites. control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of any tax incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
litigation related to the Kemper County energy facility;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company has authority fromexpressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi PSCPower Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Operating Revenues: | | | | | |
Retail revenues | $ | 854 |
| | $ | 859 |
| | $ | 776 |
|
Wholesale revenues, non-affiliates | 259 |
| | 261 |
| | 270 |
|
Wholesale revenues, affiliates | 56 |
| | 26 |
| | 76 |
|
Other revenues | 18 |
| | 17 |
| | 16 |
|
Total operating revenues | 1,187 |
| | 1,163 |
| | 1,138 |
|
Operating Expenses: | | | | | |
Fuel | 395 |
| | 343 |
| | 443 |
|
Purchased power | 25 |
| | 34 |
| | 12 |
|
Other operations and maintenance | 282 |
| | 312 |
| | 274 |
|
Depreciation and amortization | 161 |
| | 132 |
| | 123 |
|
Taxes other than income taxes | 104 |
| | 109 |
| | 94 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 4,329 |
| | 1,358 |
| | 1,311 |
|
Operating Loss | (3,142 | ) | | (195 | ) | | (173 | ) |
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 72 |
| | 124 |
| | 110 |
|
Interest expense, net of amounts capitalized | (42 | ) | | (74 | ) | | (7 | ) |
Other income (expense), net | (8 | ) | | (7 | ) | | (8 | ) |
Total other income and (expense) | 22 |
| | 43 |
| | 95 |
|
Loss Before Income Taxes | (3,120 | ) | | (152 | ) | | (78 | ) |
Income taxes (benefit) | (532 | ) | | (104 | ) | | (72 | ) |
Net Loss | (2,588 | ) | | (48 | ) | | (6 | ) |
Dividends on Preferred Stock | 2 |
| | 2 |
| | 2 |
|
Net Loss After Dividends on Preferred Stock | $ | (2,590 | ) | | $ | (50 | ) | | $ | (8 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Net Loss | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $(1), $1, and $-, respectively | (1 | ) | | 1 |
| | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 1 |
| | 1 |
| | 1 |
|
Total other comprehensive income (loss) | — |
| | 2 |
| | 1 |
|
Comprehensive Loss | $ | (2,588 | ) | | $ | (46 | ) | | $ | (5 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Operating Activities: | | | | | |
Net loss | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Adjustments to reconcile net loss to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 198 |
| | 157 |
| | 126 |
|
Deferred income taxes | (727 | ) | | (67 | ) | | 777 |
|
Investment tax credits | — |
| | — |
| | (210 | ) |
Allowance for equity funds used during construction | (72 | ) | | (124 | ) | | (110 | ) |
Pension and postretirement funding | — |
| | (47 | ) | | — |
|
Regulatory assets associated with Kemper IGCC | (19 | ) | | (12 | ) | | (61 | ) |
Estimated loss on Kemper IGCC | 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | — |
| | — |
| | (544 | ) |
Other, net | (12 | ) | | (20 | ) | | 8 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | 540 |
| | 13 |
| | 28 |
|
-Fossil fuel stock | 24 |
| | 4 |
| | (4 | ) |
-Prepaid income taxes | — |
| | 39 |
| | (35 | ) |
-Other current assets | (13 | ) | | (12 | ) | | (14 | ) |
-Accounts payable | (3 | ) | | (14 | ) | | (34 | ) |
-Accrued interest | (29 | ) | | 27 |
| | (2 | ) |
-Accrued taxes | 80 |
| | 14 |
| | (11 | ) |
-Over recovered regulatory clause revenues | (51 | ) | | (45 | ) | | 96 |
|
-Mirror CWIP | — |
| | — |
| | (271 | ) |
-Customer liability associated with Kemper refunds | (1 | ) | | (73 | ) | | 73 |
|
-Other current liabilities | (3 | ) | | 9 |
| | 2 |
|
Net cash provided from operating activities | 503 |
| | 229 |
| | 173 |
|
Investing Activities: | | | | | |
Property additions | (429 | ) | | (798 | ) | | (857 | ) |
Construction payables | (47 | ) | | (26 | ) | | (9 | ) |
Government grant proceeds | — |
| | 137 |
| | — |
|
Other investing activities | (28 | ) | | (10 | ) | | (40 | ) |
Net cash used for investing activities | (504 | ) | | (697 | ) | | (906 | ) |
Financing Activities: | | | | | |
Decrease in notes payable, net | (18 | ) | | — |
| | — |
|
Proceeds — | | | | | |
Capital contributions from parent company | 1,002 |
| | 627 |
| | 277 |
|
Long-term debt issuance to parent company | 40 |
| | 200 |
| | 275 |
|
Other long-term debt | — |
| | 1,200 |
| | — |
|
Short-term borrowings | 109 |
| | — |
| | 505 |
|
Redemptions — | | | | | |
Short-term borrowings | (109 | ) | | (478 | ) | | (5 | ) |
Long-term debt to parent company | (591 | ) | | (225 | ) | | — |
|
Capital leases | (71 | ) | | (3 | ) | | (3 | ) |
Senior notes | (35 | ) | | (300 | ) | | — |
|
Other long-term debt | (300 | ) | | (425 | ) | | (350 | ) |
Other financing activities | (2 | ) | | (2 | ) | | (1 | ) |
Net cash provided from financing activities | 25 |
| | 594 |
| | 698 |
|
Net Change in Cash and Cash Equivalents | 24 |
| | 126 |
| | (35 | ) |
Cash and Cash Equivalents at Beginning of Year | 224 |
| | 98 |
| | 133 |
|
Cash and Cash Equivalents at End of Year | $ | 248 |
| | $ | 224 |
| | $ | 98 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $29, $49, and $66 capitalized, respectively) | $ | 65 |
| | $ | 50 |
| | $ | 45 |
|
Income taxes (net of refunds) | (424 | ) | | (97 | ) | | (33 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 78 |
| | 105 |
|
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | — |
| | 301 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | |
Assets | 2017 | | 2016 |
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 248 |
| | $ | 224 |
|
Receivables — | | | |
Customer accounts receivable | 36 |
| | 29 |
|
Unbilled revenues | 41 |
| | 42 |
|
Income taxes receivable, current | 4 |
| | 544 |
|
Affiliated | 16 |
| | 15 |
|
Other accounts and notes receivable | 12 |
| | 14 |
|
Fossil fuel stock | 17 |
| | 100 |
|
Materials and supplies, current | 44 |
| | 76 |
|
Other regulatory assets, current | 125 |
| | 115 |
|
Other current assets | 9 |
| | 8 |
|
Total current assets | 552 |
| | 1,167 |
|
Property, Plant, and Equipment: | | | |
In service | 4,773 |
| | 4,865 |
|
Less: Accumulated provision for depreciation | 1,325 |
| | 1,289 |
|
Plant in service, net of depreciation | 3,448 |
| | 3,576 |
|
Construction work in progress | 84 |
| | 2,545 |
|
Total property, plant, and equipment | 3,532 |
| | 6,121 |
|
Other Property and Investments | 30 |
| | 12 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 35 |
| | 361 |
|
Other regulatory assets, deferred | 437 |
| | 518 |
|
Accumulated deferred income taxes | 247 |
| | — |
|
Other deferred charges and assets | 33 |
| | 56 |
|
Total deferred charges and other assets | 752 |
| | 935 |
|
Total Assets | $ | 4,866 |
| | $ | 8,235 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholder's Equity | 2017 | | 2016 |
| (in millions) |
Current Liabilities: | | | |
Securities due within one year — | | | |
Parent | $ | — |
| | $ | 551 |
|
Other | 989 |
| | 78 |
|
Notes payable | 4 |
| | 23 |
|
Accounts payable — | | | |
Affiliated | 59 |
| | 62 |
|
Other | 96 |
| | 135 |
|
Accrued taxes — | | | |
Accrued income taxes | 40 |
| | — |
|
Other accrued taxes | 101 |
| | 99 |
|
Unrecognized tax benefits | — |
| | 383 |
|
Accrued interest | 16 |
| | 46 |
|
Accrued compensation | 39 |
| | 42 |
|
Asset retirement obligations, current | 37 |
| | 32 |
|
Over recovered regulatory clause liabilities | — |
| | 51 |
|
Other current liabilities | 82 |
| | 36 |
|
Total current liabilities | 1,463 |
| | 1,538 |
|
Long-Term Debt (See accompanying statements) | 1,097 |
| | 2,424 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | — |
| | 756 |
|
Deferred credits related to income taxes | 372 |
| | 7 |
|
Employee benefit obligations | 116 |
| | 115 |
|
Asset retirement obligations, deferred | 137 |
| | 146 |
|
Other cost of removal obligations | 178 |
| | 170 |
|
Other regulatory liabilities, deferred | 79 |
| | 77 |
|
Other deferred credits and liabilities | 33 |
| | 26 |
|
Total deferred credits and other liabilities | 915 |
| | 1,297 |
|
Total Liabilities | 3,475 |
| | 5,259 |
|
Cumulative Redeemable Preferred Stock (See accompanying statements) | 33 |
| | 33 |
|
Common Stockholder's Equity (See accompanying statements) | 1,358 |
| | 2,943 |
|
Total Liabilities and Stockholder's Equity | $ | 4,866 |
| | $ | 8,235 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | |
| 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | |
Long-term notes payable — | | | | | | | |
5.60% due 2017 | $ | — |
| | $ | 35 |
| | | | |
1.63% due 2018 | 50 |
| | 50 |
| | | | |
5.55% due 2019 | 125 |
| | 125 |
| | | | |
4.25% to 5.40% due 2035-2042 | 630 |
| | 630 |
| | | | |
Adjustable rate (3.05% at 12/31/17) due 2018 | 900 |
| | 1,200 |
| | | | |
Total long-term notes payable | 1,705 |
| | 2,040 |
| | | | |
Other long-term debt — | | | | | | | |
Pollution control revenue bonds — | | | | | | | |
5.15% due 2028 | 43 |
| | 43 |
| | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | 40 |
| | 40 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | 270 |
| | 270 |
| | | | |
Long-term debt payable to parent company (2.27%) due 2017 | — |
| | 551 |
| | | | |
Total other long-term debt | 353 |
| | 904 |
| | | | |
Capitalized lease obligations | — |
| | 74 |
| | | | |
Unamortized debt premium | 36 |
| | 45 |
| | | | |
Unamortized debt discount | (1 | ) | | (2 | ) | | | | |
Unamortized debt issuance expense | (7 | ) | | (8 | ) | | | | |
Total long-term debt (annual interest requirement — $86 million) | 2,086 |
| | 3,053 |
| | | | |
Less amount due within one year | 989 |
| | 629 |
| | | | |
Long-term debt excluding amount due within one year | 1,097 |
| | 2,424 |
| | 44.1 | % | | 44.9 | % |
Cumulative Redeemable Preferred Stock: | | | | | | | |
$100 par value — | | | | | | | |
Authorized — 1,244,139 shares | | | | | | | |
Outstanding — 334,210 shares | | | | | | | |
4.40% to 5.25% (annual dividend requirement — $2 million) | 33 |
| | 33 |
| | 1.3 |
| | 0.6 |
|
Common Stockholder's Equity: | | | | | | | |
Common stock, without par value — | | | | | | | |
Authorized — 1,130,000 shares |
| |
| | | | |
Outstanding — 1,121,000 shares | 38 |
| | 38 |
| | | | |
Paid-in capital | 4,529 |
| | 3,525 |
| | | | |
Accumulated deficit | (3,205 | ) | | (616 | ) | | | | |
Accumulated other comprehensive loss | (4 | ) | | (4 | ) | | | | |
Total common stockholder's equity | 1,358 |
| | 2,943 |
| | 54.6 |
| | 54.5 |
|
Total Capitalization | $ | 2,488 |
| | $ | 5,400 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) |
Balance at December 31, 2014 | 1 |
| | $ | 38 |
| | $ | 2,612 |
| | $ | (559 | ) | | $ | (7 | ) | | $ | 2,084 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
Capital contributions from parent company | — |
| | — |
| | 281 |
| | — |
| | — |
| | 281 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2015 | 1 |
| | 38 |
| | 2,893 |
| | (566 | ) | | (6 | ) | | 2,359 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (50 | ) | | — |
| | (50 | ) |
Capital contributions from parent company | — |
| | — |
| | 632 |
| | — |
| | — |
| | 632 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Balance at December 31, 2016 | 1 |
| | 38 |
| | 3,525 |
| | (616 | ) | | (4 | ) | | 2,943 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (2,590 | ) | | — |
| | (2,590 | ) |
Capital contributions from parent company | — |
| | — |
| | 1,004 |
| | — |
| | — |
| | 1,004 |
|
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2017 | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,205 | ) | | $ | (4 | ) | | $ | 1,358 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other traditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The Company is subject to regulation by the FERC Mattersand the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain
NOTES (continued)
Mississippi Power Company 2017 Annual Report
components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $140 million, $231 million, and $295 million during 2017, 2016, and 2015, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. See Note 7 under "Operating Leases" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $9 million, $13 million, and $11 million in 2017, 2016, and 2015, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2017 or 2016. Fuel purchases were $8 million in 2015. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $31 million, $26 million, and $27 million in 2017, 2016, and 2015, respectively. See Note 4 for additional information.
Total power purchased from affiliates through the power pool, included in purchased power in the statement of operations, totaled $16 million, $29 million, and $7 million in 2017, 2016, and 2015, respectively.
In June 2017, the Company received a capital contribution from Southern Company of $1.0 billion. The Company used a portion of the proceeds to repay all of the $591 million outstanding principal amount of promissory notes to Southern Company. See Note 6 for additional information.
On September 15, 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible research and experimental (R&E) expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" for additional information.
The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2017, 2016, or 2015.
The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities
The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 |
| | 2016 |
| | Note |
| (in millions) |
Retiree benefit plans – regulatory assets | $ | 174 |
| | $ | 173 |
| | (a) |
Asset retirement obligations | 95 |
| | 83 |
| | (b) |
Kemper County energy facility | 88 |
| | 194 |
| | (c) |
Remaining net book value of retired assets | 44 |
| | 53 |
| | (d) |
Property tax | 43 |
| | 37 |
| | (e) |
Deferred charges related to income taxes | 36 |
| | 362 |
| | (d) |
Plant Daniel Units 3 and 4 | 36 |
| | 33 |
| | (f) |
Other regulatory assets | 28 |
| | 28 |
| | (g) |
ECO carryforward | 26 |
| | 22 |
| | (h) |
Other regulatory liabilities | — |
| | (1 | ) | | (i) |
Deferred credits related to income taxes | (377 | ) | | (9 | ) | | (j) |
Other cost of removal obligations | (178 | ) | | (170 | ) | | (k) |
Property damage | (57 | ) | | (68 | ) | | (l) |
Total regulatory assets (liabilities), net | $ | (42 | ) | | $ | 737 |
| | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(b) | To be recovered upon completion of removal activities over a period approved by the Mississippi PSC. |
| |
(c) | Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." |
| |
(d) | Recovered over the related property lives up to 48 years. |
| |
(e) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. |
| |
(f) | Represents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10-year period beginning October 2021. |
| |
(g) | Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. |
| |
(h) | Recovered through the ECO clause in the year following the deferral. |
| |
(i) | Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. |
| |
(j) | This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million, of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million, of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight-year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. |
| |
(k) | Collected in advance from customers to remove assets upon their retirement. |
| |
(l) | For additional information, see Note 1 under "Provision for Property Damage." |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Government Grants
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants). Through December 31, 2017, the Company has received grant funds of $382 million, of which $245 million of the Initial DOE Grants were used for the construction of the Kemper County energy facility, which is reflected in the Company's financial statements as a reduction to the Kemper County energy facility capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $2 million is expected to be received for allowable costs through December 31, 2017. See Note 3 under "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
Revenues
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually.
The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of the Company's total operating revenues in2017 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Except as described above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
See Note 3 under "Retail Regulatory Matters" for additional information.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Generation | $ | 2,801 |
| | $ | 2,632 |
|
Transmission | 737 |
| | 712 |
|
Distribution | 946 |
| | 916 |
|
General | 204 |
| | 520 |
|
Plant acquisition adjustment | 85 |
| | 85 |
|
Total plant in service | $ | 4,773 |
| | $ | 4,865 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause.
Depreciation, Depletion, and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.7% in 2017, 4.2% in 2016, and 4.7% in 2015. The decrease in 2017 is primarily due to lower depreciation expense as a result of recording a loss on the lignite mine in June 2017. The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities, except for the Kemper County energy facility combined cycle and related assets in service.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Details of the AROs included in the balance sheets are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Balance at beginning of year | $ | 179 |
| | $ | 177 |
|
Liabilities incurred | — |
| | 15 |
|
Liabilities settled | (23 | ) | | (23 | ) |
Accretion | 5 |
| | 5 |
|
Cash flow revisions | 13 |
| | 5 |
|
Balance at end of year | $ | 174 |
| | $ | 179 |
|
The increase in cash flow revisions in 2017 is primarily related to a revision in the closure date of the lignite mine ARO.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary.
Allowance for Funds Used During Construction
The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.7%, 6.5%, and 5.99% for the years ended December 31, 2017, 2016, and 2015, respectively. AFUDC equity was $72 million, $124 million, and $110 million in 2017, 2016, and 2015, respectively. The decrease in 2017 resulted from the Kemper IGCC project suspension in June 2017.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Municipal and Rural Associations Tariff
In 2012, theThe Company entered into a settlement agreement with itsprovides wholesale customers with respectelectric service to the Company's request for revised rates under the wholesale cost-based electric tariff. The settlement agreement provided that base rates under the cost-based electric tariff increase by approximately $23 million over a 12-month period with revised rates effective April 1, 2012. A significant portion of the difference between the requested base rate increaseCooperative Energy, East Mississippi Electric Power Association, and the agreed upon rate increase was due toCity of Collins, all located in southeastern Mississippi, under a change in the recovery methodology for the return on the Kemper IGCC CWIP. Under the settlement agreement, a portion of CWIP will continue to accrue AFUDC. The tariff customers specifically agreed to the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC with respect to (i) the accounting for Kemper IGCC-related costs that cannot be capitalized, (ii) the accounting for the lease termination and purchase of Plant Daniel Units 3 and 4, and (iii) the establishment of a regulatory asset for certain potential plant retirement costs.
Also in 2012, thelong-term cost-based, FERC approved a motion to place interim rates into effect beginning in May 2012. Later in 2012, the Company, with its wholesale customers, filed a final settlement agreement with the FERC. In 2013, the Company received an order from the FERC accepting the settlement agreement.regulated MRA tariff.
In 2013,March 2016, the Company reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an additional increase in the MRA cost-based electric tariff, which was accepted by the FERC in 2013. The 2013 settlement agreement provided thatwholesale base ratesrevenues under the MRA cost-based electric tariff, will increase by approximately $24 million annually, effective Aprilprimarily as a result of placing
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
scrubbers for Plant Daniel Units 1 2013.
In March 2014, the Company reached aand 2 in service in 2015. The settlement agreement with its wholesale customers and filed a request with the FERCbecame effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase inof $7 million under the MRA cost-based electric tariff. TheAdditionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income.
The Company expects to make a subsequent MRA filing during the second quarter 2018. The filing is intended to be consistent with the February 6, 2018 Mississippi PSC order for cost recovery of the Kemper County energy facility, including the impact of Tax Reform Legislation. The ultimate outcome of this matter cannot be determined at this time.
On September 18, 2017, the Company and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC in May 2014, provided that base rateson October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of the Company's generation services under the MRA cost-based electric tariff, increased approximately $10 million annually, effective May 1, 2014.
Includedsubject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in this settlement agreement, an adjustment to the Company's wholesale revenue requirement in a subsequent rate proceeding was allowed in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. Therefore, the Company recorded a regulatory asset as a result of a portion of the Kemper IGCC being placed in service prior to the projected date, which was fully amortized as of December 31, 2015.
On May 13, 2015, the FERC accepted a further settlement agreement between the Company and its wholesale customers to forgo a MRA cost-based electric tariff increase by, among other things, increasing the accrual of AFUDC and lowering the portion of CWIP in rate base, effective April 1, 2015. The additional resulting AFUDCrevenues is estimatednot expected to be approximately $14 million annually, of which $11 million relates to the Kemper IGCC.significant through 2020.
Fuel Cost Recovery
The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. Effective January 1, 2016,2018, the wholesale MRA fuel rate decreased $47 million annually. Effective February 1, 2016, the wholesale MB fuel rate decreased $2increased $11 million annually. At December 31, 2015, the amount of2017, over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million, which is included in over-recovered regulatory clause liabilities, current in the balance sheets was $24 million compared to an immaterial balance at December 31, 2014.sheets.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Market-Based Rate Authority
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcomeFERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of this matter cannot be determined at this time.cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Cooperative Energy Power Supply Agreement
In 2008, the Company entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to 86 MWs. On February 5, 2018, the Company and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Company's transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS amended the terms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
General
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through the Company's base rates. See Note 3 to the financial statements under "Retail Regulatory Matters" and "Kemper County Energy Facility" for additional information.
In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi.
In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.
On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC.
The ultimate outcome of these matters cannot be determined at this mattertime.
Performance Evaluation Plan
The Company's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the MPUS disputed certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to the 2010 PEP lookback filing, which remain under review, also impact the 2012 PEP lookback filing.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.
In 2014, 2015, 2016, and 2017, the Company submitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the Company submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.
On February 7, 2018, the Company revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 5 to the financial statements for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were required to be filed within six months of theextended by an order and will be in effect for two to three years. An annual report addressing the performance of all energy efficiency programs is required.
In June 2014,issued by the Mississippi PSC approvedin July 2016, until the Company's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. In November 2014,time the Mississippi PSC approved the Company's revised compliance filing, which included an increaseapproves a comprehensive portfolio plan program. The ultimate outcome of $7 million in retail revenues for the period December 2014 through December 2015.this matter cannot be determined at this time.
Performance Evaluation Plan
The Company’s retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on projected revenue requirement, and the PEP lookback filing, which is filed after the year and allows for review of the actual revenue requirement compared to the projected filing. PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability.
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In 2012,On July 6, 2017, the Mississippi PSC issued an order cancelingapproving the Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to certain costs included in the 2010 PEP lookbackEnergy Efficiency Cost Rider 2017 compliance filing, which are currently under review, also impactincreased annual retail revenues by approximately $2 million effective with the 2012 PEP lookback filing.first billing cycle for August 2017.
In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company may be entitled to $3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase.
In March 2014 and 2015,On November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing, which included a small decrease in annual PEP lookback filings for 2013 and 2014, respectively, which each indicated no surcharge or refund. The Mississippi PSC suspended each of the filings to allow more time for review.
In June 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi.
retail revenues. The ultimate outcome of these mattersthis matter cannot be determined at this time.
See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Environmental Compliance Overview Plan
In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in November 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. The Company's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of December 31, 2015, total project expenditures were $637 million, of which the Company's portion was $325 million, excluding AFUDC of $36 million.
In 2013, the Mississippi PSC approved the Company’s 2013 ECO Plan filing which proposed no change in rates.
In August 2014, the Company entered into a settlement agreement with the Sierra Club that,under which, among other things, required the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which also occurred in August 2014. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018.2018 (and the units were retired in July 2016). The Company also agreed
NOTES (continued)
Mississippi Power Company 2015 Annual Report
that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred onin April 16, 2015), and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas no later than April 2016.(which occurred in June and July 2016, respectively).
In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. This request was madeThe Mississippi PSC approved $41 million and $17 million of costs that were reclassified to minimize the potential rate impact to customers arising from pendingregulatory assets associated with Plant Watson and final environmental regulations which may require the premature retirement of some generating units. As of December 31, 2015, $5 million of Plant Greene County, costsrespectively, for amortization over five-year periods that began in July 2016 and $36 million of costs related to Plant Watson have been reclassified as regulatory assets. These costs are expected to be recovered through the ECO plan and other existing cost recovery mechanisms. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Watson and Greene County in 2016. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC.July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements.
On December 3, 2015,In August 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2015,2016, which indicated no changerequested the maximum 2% annual increase in revenue.revenues, or approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing, along with related carrying costs.
On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing, along with related carrying costs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
On February 14, 2018, the Company submitted its ECO plan filing for 2018, including the effects of Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million, primarily related to the carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. TheOn January 12, 2017, the Mississippi PSC approved the 20162017 retail fuel cost recovery factor, effective February 2017 through January 21, 2016,2018, which will resultresulted in an annual revenue decreaseincrease of approximately $120$55 million. On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2015,2017, the amount of over-recoveredunder-recovered retail fuel costs included in the balance sheetssheet in customer accounts receivable was $71approximately $6 million compared to a $3$37 million under-recovered balance over recovered at December 31, 2014.2016.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Ad Valorem Tax Adjustment
The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On September 1, 2015,July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing effective September 18, 2015,for 2017, which included an annual rate decreaseincrease of 0.35%0.85%, or $2$8 million in annual retail revenues, primarily due to average millage rates.increased assessments.
System Restoration Rider
On October 6, 2015, the Mississippi PSC approved the Company's 2015 SRR rate filing, which proposed that the SRR rate remain level at zero and the Company continue to accrue $3 million annually to the property damage reserve.
OnIn February 1, 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual. accrual of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million. These filings were suspended by the Mississippi PSC for review.
On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million. A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing.
On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018.
The ultimate outcome of this matterthese matters cannot be determined at this time.
See Note 1 to the financial statements under "Provision for Property Damage" for additional information.
Integrated Coal Gasification Combined CycleStorm Damage Cost Recovery
In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded.
Kemper IGCC County Energy Facility
Overview
Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC willCounty energy facility was designed to utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC willMWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC.County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC,County energy facility construction, the Company constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery.
Kemper IGCC
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.County energy facility. The certificated cost estimate of the Kemper IGCCCounty energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper
NOTES (continued)
Mississippi Power Company 2015 Annual Report
IGCC.approximately $0.57 billion in Cost Cap Exceptions. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88$2.88 billion,, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCCCounty energy facility was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCCCounty energy facility in service usingin August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas in August 2014price forecast had decreased significantly and currently expectsthe estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to placeissue an order (which occurred on July 6, 2017) directing the remainderCompany to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC,County energy facility, given the uncertainty as to its future.
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.
Recoveryapproximately $5.95 billion of the costs subject to the construction cost cap, and the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2015, are as follows:
|
| | | | | | | | | | | |
Cost Category | 2010 Project Estimate(f) | | Current Cost Estimate(a) | | Actual Costs |
| (in billions) |
Plant Subject to Cost Cap(b)(g) | $ | 2.40 |
| | $ | 5.29 |
| | $ | 4.83 |
|
Lignite Mine and Equipment | 0.21 | | 0.23 | | 0.23 |
CO2 Pipeline Facilities | 0.14 | | 0.11 | | 0.11 |
AFUDC(c) | 0.17 | | 0.69 | | 0.59 |
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g) | — |
| | 0.01 | | 0.01 |
General Exceptions | 0.05 | | 0.10 | | 0.09 |
Deferred Costs(e)(g) | — |
| | 0.20 | | 0.17 |
Total Kemper IGCC | $ | 2.97 |
| | $ | 6.63 |
| | $ | 6.03 |
|
| |
(a) | Amounts in the Current Cost Estimate reflect estimated costs through August 31, 2016. |
| |
(b) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the$2.88 billioncost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.
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(c) | The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.
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(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. |
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(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein. |
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(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
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(g) | Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at December 31, 2015. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2015, $3.47 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.41 billion), $2$137 million in other property and investments, $69 million in fossil fuel stock, $45 million in materials and supplies, $21 million in other regulatory assets, current, $195 million in other regulatory assets, deferred, and $11 million in other deferred charges and assets inAdditional DOE Grants. In the balance sheet.
Theaggregate, the Company does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Companyhad recorded pre-tax charges to income for revisions toof $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of $365the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($226206 million after tax), $868including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($53685 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax),.
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and $1.1 billion ($681 million after tax)include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2015, 2014, and 2013, respectively.2018 or at any future date. On February 12, 2018, the Company made the required compliance filing with the Mississippi PSC. The increases to the cost estimate inKemper
NOTESMANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 20152017 Annual Report
2015 primarily reflect costs forSettlement Agreement also requires (i) the extension of the Kemper IGCC's projected in-service date through August 31, 2016, increased efforts related to scope modifications, additional labor costs in support of start-up and operational readiness activities, and system repairs and modifications after startup testing and commissioning activities identified necessary remediation of equipment installation, fabrication, and design issues, including the refractory lining inside the gasifiers; the lignite feed and dryer systems; and the syngas cooler vessels. Any extension of the in-service date beyond August 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond August 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.
The Company's analysis of the time needed to complete the start-up and commissioning activitiesCPCN for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. Further cost increases and/or extensions of the in-service date with respectCounty energy facility to the Kemper IGCC may result from factors including, but not limitedbe modified to labor costslimit it to natural gas combined cycle operation and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of operations and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding the Company's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See "Income Tax Matters" herein for additional tax information related to the Kemper IGCC.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or(ii) the Company incurs additional costs to satisfy such parameters, there could befile a material adverse impact on the Company's financial statements.
2013 MPSC Rate Order
In January 2013, the Company entered into a settlement agreementreserve margin plan with the Mississippi PSC that was intended to establishby August 2018.
As of December 31, 2017, the process for resolving matters regarding cost recovery related tobalances associated with the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC,County energy facility regulatory assets and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013liabilities were $114 million and 3% effective January 1, 2014, which collectively were designed to collect $156$26 million, annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation discussed below.
2015 Rate Caserespectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Court decision, on July 10,Rate Case
On December 3, 2015, the Company filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) for consideration byissued the Mississippi PSC. The In-Service Asset Proposal was based upon the test period of June 2015 to May 2016, was designed to recover the Company's costs associated withRate Order regarding the Kemper IGCCCounty energy facility assets that arewere commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and was designed to collect approximately $159 million annually. On August 13, 2015, the Mississippi PSC approved the implementation of interim rates that became effective with the first billing cycle in September, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order) adopting in full a stipulation (the 2015 Stipulation) entered into between the Company and the MPUS regarding the In-Service Asset Proposal. Consistent with the 2015 Stipulation, thecosts. The In-Service Asset Rate Order providesprovided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the Company’sCompany's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs during the test period.costs. The In-Service Asset Rate Order also includesincluded a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excludes
In connection with the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. See "Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
With implementation of the new rate on December 17, 2015, the interim rates were terminated and the Company recorded a customer refund of approximately $11 million in December 2015 for the difference between the interim rates collected and the permanent rates. The refund is required to be completed by March 16, 2016.
Pursuant to the In-Service Asset Rate Order, the Company is required to file a subsequent rate request within 18 months. As part of the filing, the Company expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. The Company believes the appeal has no merit; however, an adverse outcome in this appeal could have a material impact on the Company's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. The Company expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact the Company's ability to utilize alternate financing through securitization or the February 2013 legislation.
The Company expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at December 31, 2015of$6.63 billion, the Company anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
The Company expects the Kemper IGCC to qualify for additional DOE grants included in the recently passed Consolidated Appropriations Act of 2015, which are expected to be used to reduce future rate impacts for customers. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Assets and Liabilities
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting the Company the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.
In August 2014, the Company requested confirmation by the Mississippi PSC of the Company's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interimwholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortizationfees over periods for these regulatory assets varyranging from two years to 10 years as set forth inyears. On July 6, 2017, the In-Service Asset Rate Order. As of December 31, 2015,Mississippi PSC issued an order requiring the balance associated with theseCompany to establish a regulatory assets was $120 million. Other regulatory assets associated with the remainder ofliability account to maintain current rates related to the Kemper IGCC totaled $96 million asCounty energy facility following the July 2017 completion of December 31, 2015. Thethe amortization period for certain of these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
regulatory assets. See "2013 MPSC Rate Order""FERC Matters" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.
The In-Service Asset Rate Order requires the Company to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital,2016 settlement agreement with the first occurring as of May 31, 2016. As of December 31, 2015, the Company recorded a related regulatory liability of approximately $2 million. See "2015 Rate Case" herein for additional information.wholesale customers.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, theThe Company will ownowns the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCCCounty energy facility site. The mine started commercial operation in June 2013.
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managingresponsible for the mining operations. The contract with Liberty Fuels is effectiveoperations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company currently providesprovided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.
In addition, the Company has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. The Company hasrecovery and entered into agreementsan agreement with Denbury Onshore (Denbury), to purchase the captured CO2. Denbury has the right to terminate the contract at any time because the Company did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a subsidiary of Denbury Resourcescomplaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and the Company and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. The Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
could have a material impact on the Company's results of operations, financial condition, and liquidity. The Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
On June 9, 2016, Treetop, Midstream Services,Greenleaf CO2 Solutions, LLC (Treetop)(Greenleaf), an affiliate ofTenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group LLCfiled a complaint against the Company, Southern Company, and a subsidiarySCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of Tengrys, LLC,contract on the part of the Company, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, the Company, and SCS moved to compel arbitration pursuant to which Denbury will purchase 70%the terms of the CO2 capturedcontract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, the Company reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
Regulated utility businesses can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income in the subsequent tax year.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $372 million and a $375 million increase in regulatory liabilities as of December 31, 2017, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Mississippi PSC. On January 31, 2018, SCS, on behalf of the traditional electric operating companies (including the Company), filed with the FERC a reduction to the Company's open access transmission tariff charge for 2018 to reflect the revised federal corporate tax rate. See Note 3 to the financial statements under "Regulatory Matters" for additional information regarding the Company's rate filings to reflect the impacts of the Tax Reform Legislation.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, approximately $50 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year and approximately $10 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. Additionally, Southern Company will record an abandonment loss on its 2018 corporate income tax return, which may not be fully realized should Southern Company have a NOL in 2018. See Notes 3 and Treetop will purchase 30%5 to the financial statements under "Kemper County Energy Facility" and "Current and Deferred Income Taxes," respectively, for additional information. The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Section 174 Research and Experimental Deduction
Southern Company, on behalf of the Company, has reflected deductions for R&E expenditures related to the Kemper County energy facility in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of this approval, the Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 capturedand other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
In 2013, the Company submitted a claim under the Deep Horizon Economic and Property Damages Settlement Agreement associated with the oil spill that occurred in the Gulf of Mexico. The ultimate outcome of this matter cannot be determined at this time.
In 2016, the SEC began conducting a formal investigation of Southern Company and the Company concerning the estimated costs and expected in-service date of the Kemper County energy facility. On November 30, 2017, the SEC staff notified Southern Company that it had concluded its investigation with no recommended enforcement action.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
The Company is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates the Company is permitted to charge customers based on allowable costs. As a result, the Company applies accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Kemper County Energy Facility Rate Recovery
For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. The Company recorded total pre-tax charges to income related to the Kemper County energy facility of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.
As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as the Company's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper County energy facility, the estimated construction costs and project completion date are no longer considered significant accounting estimates.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge of $78 million associated with the Kemper Settlement Agreement.
In the aggregate, since the Kemper County energy facility project started, the Company has incurred charges of $6.20 billion ($4.14 billion after tax) through December 31, 2017. See Note 11 to the financial statements for additional information on the individual charges by quarter.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges, and no longer represents a critical accounting estimate.
See Note 3 to the financial statements under "Kemper County Energy Facility" for additional information.
Federal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Retail Regulatory Matters – Rate Plans" and "Current and Deferred Income Taxes," respectively, for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
Given the significant judgment involved in estimating AROs, the Company considers the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. For 2015 and prior years, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. Beginning in 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $4 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $2 million or less change in total annual benefit expense and a $25 million or less change in projected obligations.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Allowance for Funds Used During Construction
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.7%, 6.5%, and 5.99% for the years ended December 31, 2017, 2016, and 2015, respectively. The AFUDC rate is applied to CWIP consistent with jurisdictional regulatory treatment. AFUDC equity was $72 million, $124 million, and $110 million in 2017, 2016, and 2015, respectively. The decrease in 2017 resulted from the Kemper IGCC. County energy facility project suspension in June 2017.
Unbilled Revenues
Revenues related to the retail sale of electricity are recorded when electricity is delivered to customers. However, the determination of KWH sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers, but not yet metered and billed, are estimated. Components of the unbilled revenue estimates include total KWH territorial supply, total KWH billed, estimated total electricity lost in delivery, and customer usage. These components can fluctuate as a result of a number of factors including weather, generation patterns, power delivery volume, and other operational constraints. These factors can be unpredictable and can vary from historical trends. As a result, the overall estimate of unbilled revenues could be significantly affected, which could have a material impact on the Company's results of operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, income tax, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable and records a tax asset or liability if it is more likely than not that a tax position will be sustained. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements with Denbury and Treetop provide Denbury and Treetop with termination rights asa lease determination has not been made at this time. While the Company has not satisfiedyet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its contractual obligationfinancial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to deliver captured CO2Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview and Sources of Capital
Earnings for all periods presented were negatively affected by May 11, 2015. Since May 11, 2015,charges associated with the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" herein and Note 3 to the financial statements for additional information.
The Company's cash requirements primarily consist of funding ongoing operations, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms.
The Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company. Specifically, the Company has been engagedinformed by Southern Company that in ongoing discussionsthe event sufficient funds are not available from external sources, Southern Company intends to provide the Company with its off-takers regardingloans and/or equity contributions sufficient to fund the statusremaining indebtedness scheduled to mature and other cash needs over the next 12 months. For additional information, see Note 6 to the financial statements under "Going Concern."
On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the CO2 delivery schedule as well as other issuesproceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.
In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ended September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. government related to the CO2 agreements. settlement concerning deductible R&E expenditures. See Note 5 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.
As of December 31, 2017, the Company's current liabilities exceeded current assets by approximately $911 million primarily due to a result of discussions$900 million unsecured term loan that matures on March 31, 2018. The Company expects to refinance the unsecured term loan with Treetop, on August 3, 2015,external security issuances and/or borrowings from financial institutions or Southern Company. To fund the Company's capital needs over the next 12 months, the Company agreedintends to amend certain provisionsutilize operating cash flows, external security issuances, lines of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO2 off-takers undercredit, bank term loans, equity contributions from Southern Company, and, to the Cleanextent necessary, loans from Southern Company.
The Company's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. The Company plans to obtain the funds required for construction and other purposes from operating cash flows, lines of credit,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO2 contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in the Company's revenuesCompany 2017 Annual Report
bank term loans, external security issuances, commercial paper, to the extent the Company is eligible to participate, and loans and/or equity contributions from Southern Company.
The Company's investments in the qualified pension plan increased in value as of December 31, 2017 as compared to December 31, 2016. No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated during 2018.
Net cash provided from operating activities totaled $503 million for 2017, an increase of $274 million as compared to 2016. The increase in cash provided from operating activities in 2017 was primarily due to tax refunds associated with the approval by the JCT of the Section 174 R&E settlement, largely offset by a decrease in income taxes related to the Kemper County energy facility and Tax Reform Legislation. Net cash provided from operating activities totaled $229 million for 2016, an increase of $56 million as compared to 2015. The increase in cash provided from operating activities in 2016 was primarily due to repayment in 2015 of ITCs relating to the Kemper County energy facility, as well as the 2015 mirror CWIP refund, partially offset by lower income tax benefits related to the Kemper County energy facility in 2016 and lower fuel rates in 2016.
Net cash used for investing activities in 2017, 2016, and 2015 totaled $504 million, $697 million, and $906 million, respectively. The cash used for investing activities in all years presented was primarily due to gross property additions related to the Kemper County energy facility. The cash used for investing activities in 2016 was partially offset by the receipt of Additional DOE Grants. The cash used for investing activities in 2015 also included gross property additions related to the Plant Daniel scrubber project.
Net cash provided from financing activities totaled $25 million in 2017 primarily due to capital contributions from Southern Company, largely offset by redemptions of long-term debt and short-term borrowings. Net cash provided from financing activities totaled $594 million in 2016 primarily due to long-term debt financings and capital contributions from Southern Company, partially offset by a decrease in short-term borrowings and redemptions of long-term debt. Net cash provided from financing activities totaled $698 million in 2015 primarily due to short-term borrowings, capital contributions from Southern Company, and long-term debt financings, partially offset by redemptions of long-term debt.
Significant balance sheet changes as of December 31, 2017 compared to 2016 include decreases of $2.5 billion in CWIP, a net change of $1.0 billion in accumulated deferred income taxes, an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year – other. Securities due within one year – parent decreased $551 million due to the repayment of promissory notes to Southern Company. Other significant balance sheet changes include $326 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the approval by the JCT of the Section 174 R&E settlement. The Company also had an increase of $365 million in deferred credits related to income taxes primarily resulting from the impacts of Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 3 and 5 to the financial statements under "Kemper County Energy Facility" and "Section 174 Research and Experimental Deduction," respectively, for additional information.
The Company's ratio of common equity to total capitalization plus short-term debt was 39% and 49% at December 31, 2017 and 2016, respectively. The decrease was due to Kemper IGCC losses. See Note 6 to the financial statements for additional information.
The issuance of securities by the Company is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, the Company files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the FERC are continuously monitored and appropriate filings are made to ensure flexibility in raising capital. Any future financing through secured debt would also require approval by the Mississippi PSC.
The Southern Company system does not ablemaintain a centralized cash or money pool. Therefore, funds of the Company are not commingled with funds of any other company in the Southern Company system.
At December 31, 2017, the Company had approximately $248 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were $100 million, all of which is unused. In November 2017, the Company amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to the Company's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of December 31, 2017 was approximately $40 million. In addition, the Company had approximately $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode subsequent to December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Most of these bank credit arrangements, as well as the Company's term loan agreement, contain covenants that limit debt levels and typically contain cross acceleration to other indebtedness (including guarantee obligations) of the Company. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the Company defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, the Company was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.
Subject to applicable market conditions, the Company expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowing were as follows:
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at the End of the Period | | Short-term Debt During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 4 |
| | 3.8 | % | | $ | 18 |
| | 3.0 | % | | $ | 36 |
|
December 31, 2016 | $ | 23 |
| | 2.6 | % | | $ | 112 |
| | 2.0 | % | | $ | 500 |
|
December 31, 2015 | $ | 500 |
| | 1.4 | % | | $ | 372 |
| | 1.3 | % | | $ | 515 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31. |
Financing Activities
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Bank Term Loans and Senior Notes
In March 2017, the Company issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In June 2017, the Company used a portion of the proceeds from Southern Company equity contributions to prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018, and to repay $10 million of the outstanding principal amount of bank loans. See "Parent Company Loans and Equity Contributions" herein for more information.
This unsecured term loan has covenants that limit debt levels to 65% of total capitalization, as defined in the agreement. For purposes of this definition, debt excludes the long-term debt payable to affiliated trusts and other hybrid securities. In addition, this unsecured term loan contains cross-acceleration provisions to other debt (including guarantee obligations) that would be triggered if the Company defaulted on debt above a specified threshold, the payment of which was then accelerated. The Company is currently in compliance with all such covenants.
In August 2017, the Company repaid a $12.5 million short-term bank note.
In November 2017, the Company repaid at maturity $35 million aggregate principal amount of Series 2007A 5.60% Senior Notes.
Parent Company Loans and Equity Contributions
In February 2017, the Company amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
In September 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note 5 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.
Credit Rating Risk
At December 31, 2017, the Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of the Company's credit rating to below investment grade by two of the three rating agencies.
There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At December 31, 2017, the maximum amount of potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $241 million.
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets, or at a minimum the cost at which it does so.
On March 1, 2017, Moody's downgraded the senior unsecured debt rating of the Company to Ba1 from Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
On March 30, 2017, Fitch placed the ratings of the Company on rating watch negative.
On June 22, 2017, Moody's placed the ratings of the Company on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for the Company from under review to stable.
While it is unclear how the credit rating agencies, the FERC, and the Mississippi PSC may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's credit ratings could be negatively affected. See Note 3 to the financial statements under "Retail Regulatory Matters" for additional information.
Market Price Risk
Due to cost-based rate regulation and other various cost recovery mechanisms, the Company continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
To mitigate future exposure to a change in interest rates, the Company may enter into derivatives that have been designated as hedges. The weighted average interest rate on $40 million of long-term variable interest rate exposure at December 31, 2017 was 2.49%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would have an immaterial effect on annualized interest expense at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases. The Company continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:
|
| | | | | | | |
| 2017 Changes | | 2016 Changes |
| Fair Value |
| (in millions) |
Contracts outstanding at the beginning of the period, assets (liabilities), net | $ | (7 | ) | | $ | (47 | ) |
Contracts realized or settled | 8 |
| | 29 |
|
Current period changes(*) | (8 | ) | | 11 |
|
Contracts outstanding at the end of the period, assets (liabilities), net | $ | (7 | ) | | $ | (7 | ) |
| |
(*) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
The net hedge volumes of energy-related derivative contracts, all of which are natural gas swaps, for the years ended December 31 were as follows:
|
| | | | | |
| 2017 | | 2016 |
| mmBtu Volume |
| (in millions) |
Total hedge volume | 53 |
| | 36 |
|
For natural gas hedges, the weighted average swap contract cost above market prices was approximately $0.14 per mmBtu as of December 31, 2017 and $0.19 per mmBtu as of December 31, 2016. The options outstanding were immaterial for the reporting periods presented. The costs associated with natural gas hedges are recovered through the Company's ECMs.
At December 31, 2017 and 2016, substantially all of the Company's energy-related derivative contracts were designated as regulatory hedges and were related to the Company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2017 were as follows:
|
| | | | | | | | | | | |
| Fair Value Measurements December 31, 2017 |
| Total | | Maturity |
| Fair Value | | Year 1 | | Years 2&3 |
| (in millions) |
Level 1 | $ | — |
| | $ | — |
| | $ | — |
|
Level 2 | (7 | ) | | (5 | ) | | (2 | ) |
Level 3 | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period | $ | (7 | ) | | $ | (5 | ) | | $ | (2 | ) |
The Company is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Therefore, the Company does not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements.
Capital Requirements and Contractual Obligations
Approximately $900 million will be required through December 31, 2018 to fund maturities of long-term debt. In addition, the Company has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode subsequent to December 31, 2017. See "Overview and Sources of Capital" herein for additional information.
The construction program of the Company is currently estimated to be $213 million for 2018, $199 million for 2019, $193 million for 2020, $167 million for 2021, and $118 million for 2022. These estimated program amounts also include capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $14 million, $16 million, $17 million, $13 million, and $3 million for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.
The Company also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in the Company's ARO liabilities. These costs, which could change as the Company continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $23 million, $7 million, $7 million, $9 million, and $12 million for the years 2018, 2019, 2020, 2021, and 2022, respectively. See Note 1 to the financial statements under "Asset Retirement Obligations and Other Costs of Removal" for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends, unrecognized tax benefits, pension and other post-retirement benefit plans, leases, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 10 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 990 |
| | $ | 125 |
| | $ | 270 |
| | $ | 673 |
| | $ | 2,058 |
|
Interest | 86 |
| | 106 |
| | 79 |
| | 552 |
| | 823 |
|
Preferred stock dividends(b) | 2 |
| | 3 |
| | 3 |
| | — |
| | 8 |
|
Financial derivative obligations(c) | 6 |
| | 3 |
| | — |
| | — |
| | 9 |
|
Operating leases(d) | 3 |
| | 5 |
| | 4 |
| | 7 |
| | 19 |
|
Purchase commitments — | | | | | | | | | |
Capital(e) | 213 |
| | 379 |
| | 269 |
| | — |
| | 861 |
|
Fuel(f) | 280 |
| | 329 |
| | 191 |
| | 175 |
| | 975 |
|
Long-term service agreements(g) | 33 |
| | 75 |
| | 49 |
| | 245 |
| | 402 |
|
Purchased power(h) | 11 |
| | 29 |
| | 36 |
| | 454 |
| | 530 |
|
Pension and other postretirement benefits plans(i) | 7 |
| | 15 |
| | — |
| | — |
| | 22 |
|
Total | $ | 1,631 |
| | $ | 1,069 |
| | $ | 901 |
| | $ | 2,106 |
| | $ | 5,707 |
|
| |
(a) | All amounts are reflected based on final maturity dates except for amounts related to certain revenue bonds. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates as of December 31, 2017, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately). For additional information, see Note 6 to the financial statements. |
| |
(b) | Preferred stock does not mature; therefore, amounts are provided for the next five years only. |
| |
(c) | Derivative obligations are for energy-related derivatives. For additional information, see Notes 1 and 10 to the financial statements. |
| |
(d) | See Note 7 to the financial statements for additional information. |
| |
(e) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under long-term service agreements, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" for additional information. |
| |
(f) | Fuel commitments include coal and natural gas purchases, as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery. Amounts reflected for natural gas purchase commitments have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(g) | Long-term service agreements include price escalation based on inflation indices. |
| |
(h) | Purchased power represents estimated minimum long-term commitments for the purchase of solar energy. Energy costs associated with solar PPAs are recovered through the fuel clause. See Notes 3 and 7 to the financial statements for additional information. |
| |
(i) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan and postretirement benefit plans contributions, financing activities, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, storm damage cost recovery and repairs, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of any tax incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;
litigation related to the Kemper County energy facility;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power Company 2017 Annual Report
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Operating Revenues: | | | | | |
Retail revenues | $ | 854 |
| | $ | 859 |
| | $ | 776 |
|
Wholesale revenues, non-affiliates | 259 |
| | 261 |
| | 270 |
|
Wholesale revenues, affiliates | 56 |
| | 26 |
| | 76 |
|
Other revenues | 18 |
| | 17 |
| | 16 |
|
Total operating revenues | 1,187 |
| | 1,163 |
| | 1,138 |
|
Operating Expenses: | | | | | |
Fuel | 395 |
| | 343 |
| | 443 |
|
Purchased power | 25 |
| | 34 |
| | 12 |
|
Other operations and maintenance | 282 |
| | 312 |
| | 274 |
|
Depreciation and amortization | 161 |
| | 132 |
| | 123 |
|
Taxes other than income taxes | 104 |
| | 109 |
| | 94 |
|
Estimated loss on Kemper IGCC | 3,362 |
| | 428 |
| | 365 |
|
Total operating expenses | 4,329 |
| | 1,358 |
| | 1,311 |
|
Operating Loss | (3,142 | ) | | (195 | ) | | (173 | ) |
Other Income and (Expense): | | | | | |
Allowance for equity funds used during construction | 72 |
| | 124 |
| | 110 |
|
Interest expense, net of amounts capitalized | (42 | ) | | (74 | ) | | (7 | ) |
Other income (expense), net | (8 | ) | | (7 | ) | | (8 | ) |
Total other income and (expense) | 22 |
| | 43 |
| | 95 |
|
Loss Before Income Taxes | (3,120 | ) | | (152 | ) | | (78 | ) |
Income taxes (benefit) | (532 | ) | | (104 | ) | | (72 | ) |
Net Loss | (2,588 | ) | | (48 | ) | | (6 | ) |
Dividends on Preferred Stock | 2 |
| | 2 |
| | 2 |
|
Net Loss After Dividends on Preferred Stock | $ | (2,590 | ) | | $ | (50 | ) | | $ | (8 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Net Loss | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $(1), $1, and $-, respectively | (1 | ) | | 1 |
| | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 1 |
| | 1 |
| | 1 |
|
Total other comprehensive income (loss) | — |
| | 2 |
| | 1 |
|
Comprehensive Loss | $ | (2,588 | ) | | $ | (46 | ) | | $ | (5 | ) |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Operating Activities: | | | | | |
Net loss | $ | (2,588 | ) | | $ | (48 | ) | | $ | (6 | ) |
Adjustments to reconcile net loss to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 198 |
| | 157 |
| | 126 |
|
Deferred income taxes | (727 | ) | | (67 | ) | | 777 |
|
Investment tax credits | — |
| | — |
| | (210 | ) |
Allowance for equity funds used during construction | (72 | ) | | (124 | ) | | (110 | ) |
Pension and postretirement funding | — |
| | (47 | ) | | — |
|
Regulatory assets associated with Kemper IGCC | (19 | ) | | (12 | ) | | (61 | ) |
Estimated loss on Kemper IGCC | 3,179 |
| | 428 |
| | 365 |
|
Income taxes receivable, non-current | — |
| | — |
| | (544 | ) |
Other, net | (12 | ) | | (20 | ) | | 8 |
|
Changes in certain current assets and liabilities — | | | | | |
-Receivables | 540 |
| | 13 |
| | 28 |
|
-Fossil fuel stock | 24 |
| | 4 |
| | (4 | ) |
-Prepaid income taxes | — |
| | 39 |
| | (35 | ) |
-Other current assets | (13 | ) | | (12 | ) | | (14 | ) |
-Accounts payable | (3 | ) | | (14 | ) | | (34 | ) |
-Accrued interest | (29 | ) | | 27 |
| | (2 | ) |
-Accrued taxes | 80 |
| | 14 |
| | (11 | ) |
-Over recovered regulatory clause revenues | (51 | ) | | (45 | ) | | 96 |
|
-Mirror CWIP | — |
| | — |
| | (271 | ) |
-Customer liability associated with Kemper refunds | (1 | ) | | (73 | ) | | 73 |
|
-Other current liabilities | (3 | ) | | 9 |
| | 2 |
|
Net cash provided from operating activities | 503 |
| | 229 |
| | 173 |
|
Investing Activities: | | | | | |
Property additions | (429 | ) | | (798 | ) | | (857 | ) |
Construction payables | (47 | ) | | (26 | ) | | (9 | ) |
Government grant proceeds | — |
| | 137 |
| | — |
|
Other investing activities | (28 | ) | | (10 | ) | | (40 | ) |
Net cash used for investing activities | (504 | ) | | (697 | ) | | (906 | ) |
Financing Activities: | | | | | |
Decrease in notes payable, net | (18 | ) | | — |
| | — |
|
Proceeds — | | | | | |
Capital contributions from parent company | 1,002 |
| | 627 |
| | 277 |
|
Long-term debt issuance to parent company | 40 |
| | 200 |
| | 275 |
|
Other long-term debt | — |
| | 1,200 |
| | — |
|
Short-term borrowings | 109 |
| | — |
| | 505 |
|
Redemptions — | | | | | |
Short-term borrowings | (109 | ) | | (478 | ) | | (5 | ) |
Long-term debt to parent company | (591 | ) | | (225 | ) | | — |
|
Capital leases | (71 | ) | | (3 | ) | | (3 | ) |
Senior notes | (35 | ) | | (300 | ) | | — |
|
Other long-term debt | (300 | ) | | (425 | ) | | (350 | ) |
Other financing activities | (2 | ) | | (2 | ) | | (1 | ) |
Net cash provided from financing activities | 25 |
| | 594 |
| | 698 |
|
Net Change in Cash and Cash Equivalents | 24 |
| | 126 |
| | (35 | ) |
Cash and Cash Equivalents at Beginning of Year | 224 |
| | 98 |
| | 133 |
|
Cash and Cash Equivalents at End of Year | $ | 248 |
| | $ | 224 |
| | $ | 98 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $29, $49, and $66 capitalized, respectively) | $ | 65 |
| | $ | 50 |
| | $ | 45 |
|
Income taxes (net of refunds) | (424 | ) | | (97 | ) | | (33 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 78 |
| | 105 |
|
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | — |
| | 301 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | |
Assets | 2017 | | 2016 |
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 248 |
| | $ | 224 |
|
Receivables — | | | |
Customer accounts receivable | 36 |
| | 29 |
|
Unbilled revenues | 41 |
| | 42 |
|
Income taxes receivable, current | 4 |
| | 544 |
|
Affiliated | 16 |
| | 15 |
|
Other accounts and notes receivable | 12 |
| | 14 |
|
Fossil fuel stock | 17 |
| | 100 |
|
Materials and supplies, current | 44 |
| | 76 |
|
Other regulatory assets, current | 125 |
| | 115 |
|
Other current assets | 9 |
| | 8 |
|
Total current assets | 552 |
| | 1,167 |
|
Property, Plant, and Equipment: | | | |
In service | 4,773 |
| | 4,865 |
|
Less: Accumulated provision for depreciation | 1,325 |
| | 1,289 |
|
Plant in service, net of depreciation | 3,448 |
| | 3,576 |
|
Construction work in progress | 84 |
| | 2,545 |
|
Total property, plant, and equipment | 3,532 |
| | 6,121 |
|
Other Property and Investments | 30 |
| | 12 |
|
Deferred Charges and Other Assets: | | | |
Deferred charges related to income taxes | 35 |
| | 361 |
|
Other regulatory assets, deferred | 437 |
| | 518 |
|
Accumulated deferred income taxes | 247 |
| | — |
|
Other deferred charges and assets | 33 |
| | 56 |
|
Total deferred charges and other assets | 752 |
| | 935 |
|
Total Assets | $ | 4,866 |
| | $ | 8,235 |
|
The accompanying notes are an integral part of these financial statements.
BALANCE SHEETS
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholder's Equity | 2017 | | 2016 |
| (in millions) |
Current Liabilities: | | | |
Securities due within one year — | | | |
Parent | $ | — |
| | $ | 551 |
|
Other | 989 |
| | 78 |
|
Notes payable | 4 |
| | 23 |
|
Accounts payable — | | | |
Affiliated | 59 |
| | 62 |
|
Other | 96 |
| | 135 |
|
Accrued taxes — | | | |
Accrued income taxes | 40 |
| | — |
|
Other accrued taxes | 101 |
| | 99 |
|
Unrecognized tax benefits | — |
| | 383 |
|
Accrued interest | 16 |
| | 46 |
|
Accrued compensation | 39 |
| | 42 |
|
Asset retirement obligations, current | 37 |
| | 32 |
|
Over recovered regulatory clause liabilities | — |
| | 51 |
|
Other current liabilities | 82 |
| | 36 |
|
Total current liabilities | 1,463 |
| | 1,538 |
|
Long-Term Debt (See accompanying statements) | 1,097 |
| | 2,424 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | — |
| | 756 |
|
Deferred credits related to income taxes | 372 |
| | 7 |
|
Employee benefit obligations | 116 |
| | 115 |
|
Asset retirement obligations, deferred | 137 |
| | 146 |
|
Other cost of removal obligations | 178 |
| | 170 |
|
Other regulatory liabilities, deferred | 79 |
| | 77 |
|
Other deferred credits and liabilities | 33 |
| | 26 |
|
Total deferred credits and other liabilities | 915 |
| | 1,297 |
|
Total Liabilities | 3,475 |
| | 5,259 |
|
Cumulative Redeemable Preferred Stock (See accompanying statements) | 33 |
| | 33 |
|
Common Stockholder's Equity (See accompanying statements) | 1,358 |
| | 2,943 |
|
Total Liabilities and Stockholder's Equity | $ | 4,866 |
| | $ | 8,235 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | |
| 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | |
Long-term notes payable — | | | | | | | |
5.60% due 2017 | $ | — |
| | $ | 35 |
| | | | |
1.63% due 2018 | 50 |
| | 50 |
| | | | |
5.55% due 2019 | 125 |
| | 125 |
| | | | |
4.25% to 5.40% due 2035-2042 | 630 |
| | 630 |
| | | | |
Adjustable rate (3.05% at 12/31/17) due 2018 | 900 |
| | 1,200 |
| | | | |
Total long-term notes payable | 1,705 |
| | 2,040 |
| | | | |
Other long-term debt — | | | | | | | |
Pollution control revenue bonds — | | | | | | | |
5.15% due 2028 | 43 |
| | 43 |
| | | | |
Variable rates (2.45% to 2.50% at 12/31/17) due 2018 | 40 |
| | 40 |
| | | | |
Plant Daniel revenue bonds (7.13%) due 2021 | 270 |
| | 270 |
| | | | |
Long-term debt payable to parent company (2.27%) due 2017 | — |
| | 551 |
| | | | |
Total other long-term debt | 353 |
| | 904 |
| | | | |
Capitalized lease obligations | — |
| | 74 |
| | | | |
Unamortized debt premium | 36 |
| | 45 |
| | | | |
Unamortized debt discount | (1 | ) | | (2 | ) | | | | |
Unamortized debt issuance expense | (7 | ) | | (8 | ) | | | | |
Total long-term debt (annual interest requirement — $86 million) | 2,086 |
| | 3,053 |
| | | | |
Less amount due within one year | 989 |
| | 629 |
| | | | |
Long-term debt excluding amount due within one year | 1,097 |
| | 2,424 |
| | 44.1 | % | | 44.9 | % |
Cumulative Redeemable Preferred Stock: | | | | | | | |
$100 par value — | | | | | | | |
Authorized — 1,244,139 shares | | | | | | | |
Outstanding — 334,210 shares | | | | | | | |
4.40% to 5.25% (annual dividend requirement — $2 million) | 33 |
| | 33 |
| | 1.3 |
| | 0.6 |
|
Common Stockholder's Equity: | | | | | | | |
Common stock, without par value — | | | | | | | |
Authorized — 1,130,000 shares |
| |
| | | | |
Outstanding — 1,121,000 shares | 38 |
| | 38 |
| | | | |
Paid-in capital | 4,529 |
| | 3,525 |
| | | | |
Accumulated deficit | (3,205 | ) | | (616 | ) | | | | |
Accumulated other comprehensive loss | (4 | ) | | (4 | ) | | | | |
Total common stockholder's equity | 1,358 |
| | 2,943 |
| | 54.6 |
| | 54.5 |
|
Total Capitalization | $ | 2,488 |
| | $ | 5,400 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings (Accumulated Deficit) | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (in millions) |
Balance at December 31, 2014 | 1 |
| | $ | 38 |
| | $ | 2,612 |
| | $ | (559 | ) | | $ | (7 | ) | | $ | 2,084 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (8 | ) | | — |
| | (8 | ) |
Capital contributions from parent company | — |
| | — |
| | 281 |
| | — |
| | — |
| | 281 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2015 | 1 |
| | 38 |
| | 2,893 |
| | (566 | ) | | (6 | ) | | 2,359 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (50 | ) | | — |
| | (50 | ) |
Capital contributions from parent company | — |
| | — |
| | 632 |
| | — |
| | — |
| | 632 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Balance at December 31, 2016 | 1 |
| | 38 |
| | 3,525 |
| | (616 | ) | | (4 | ) | | 2,943 |
|
Net loss after dividends on preferred stock | — |
| | — |
| | — |
| | (2,590 | ) | | — |
| | (2,590 | ) |
Capital contributions from parent company | — |
| | — |
| | 1,004 |
| | — |
| | — |
| | 1,004 |
|
Other | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance at December 31, 2017 | 1 |
| | $ | 38 |
| | $ | 4,529 |
| | $ | (3,205 | ) | | $ | (4 | ) | | $ | 1,358 |
|
The accompanying notes are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
Mississippi Power Company 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Mississippi Power Company (the Company) is a wholly-owned subsidiary of Southern Company, which is the parent company of the Company and three other similartraditional electric operating companies, as well as Southern Power, Southern Company Gas (as of July 1, 2016), SCS, Southern Linc, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, PowerSecure, Inc. (PowerSecure) (as of May 9, 2016), and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company provides electric service to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The Company is subject to regulation by the FERC and the Mississippi PSC. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual arrangements. Additionally,term, as well as longer-term contractual commitments, including PPAs.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements, if material. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts remain in place, sustained oilat the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price reductions couldfor contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in significantly lower revenues thana cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain
NOTES (continued)
Mississippi Power Company 2017 Annual Report
components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company forecastedwill adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to equipment and cellular towers where the Company is the lessee and to equipment where the Company is the lessor. The Company is currently analyzing pole attachment agreements and a lease determination has not been made at this time. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be availablerecognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to offset customer rate impacts, which couldthe exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Notes 5 and 8 for disclosures impacted by ASU 2016-09.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $140 million, $231 million, and $295 million during 2017, 2016, and 2015, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. See Note 7 under "Operating Leases" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $9 million, $13 million, and $11 million in 2017, 2016, and 2015, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility. There were no fuel purchases in 2017 or 2016. Fuel purchases were $8 million in 2015. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $31 million, $26 million, and $27 million in 2017, 2016, and 2015, respectively. See Note 4 for additional information.
Total power purchased from affiliates through the power pool, included in purchased power in the statement of operations, totaled $16 million, $29 million, and $7 million in 2017, 2016, and 2015, respectively.
In June 2017, the Company received a capital contribution from Southern Company of $1.0 billion. The Company used a portion of the proceeds to repay all of the $591 million outstanding principal amount of promissory notes to Southern Company. See Note 6 for additional information.
On September 15, 2017, the Company issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. The Company borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible research and experimental (R&E) expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" for additional information.
The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2017, 2016, or 2015.
The traditional electric operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information.
Regulatory Assets and Liabilities
The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 |
| | 2016 |
| | Note |
| (in millions) |
Retiree benefit plans – regulatory assets | $ | 174 |
| | $ | 173 |
| | (a) |
Asset retirement obligations | 95 |
| | 83 |
| | (b) |
Kemper County energy facility | 88 |
| | 194 |
| | (c) |
Remaining net book value of retired assets | 44 |
| | 53 |
| | (d) |
Property tax | 43 |
| | 37 |
| | (e) |
Deferred charges related to income taxes | 36 |
| | 362 |
| | (d) |
Plant Daniel Units 3 and 4 | 36 |
| | 33 |
| | (f) |
Other regulatory assets | 28 |
| | 28 |
| | (g) |
ECO carryforward | 26 |
| | 22 |
| | (h) |
Other regulatory liabilities | — |
| | (1 | ) | | (i) |
Deferred credits related to income taxes | (377 | ) | | (9 | ) | | (j) |
Other cost of removal obligations | (178 | ) | | (170 | ) | | (k) |
Property damage | (57 | ) | | (68 | ) | | (l) |
Total regulatory assets (liabilities), net | $ | (42 | ) | | $ | 737 |
| | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. |
| |
(b) | To be recovered upon completion of removal activities over a period approved by the Mississippi PSC. |
| |
(c) | Includes $114 million of regulatory assets and $26 million of regulatory liabilities to be recovered in rates over periods of eight and six years, respectively. For additional information, see Note 3 under "Kemper County Energy Facility – Rate Recovery – Kemper Settlement Agreement." |
| |
(d) | Recovered over the related property lives up to 48 years. |
| |
(e) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" for additional information. |
| |
(f) | Represents the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term, which will be amortized over a 10-year period beginning October 2021. |
| |
(g) | Comprised of vacation pay, loss on reacquired debt, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the Mississippi PSC over periods which may range up to 50 years. This amount also includes fuel-hedging assets and liabilities which are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the ECM. |
| |
(h) | Recovered through the ECO clause in the year following the deferral. |
| |
(i) | Comprised of numerous immaterial components including deferred income tax credits and other miscellaneous liabilities that are recorded and refunded or amortized as approved by the Mississippi PSC generally over periods not exceeding one year. |
| |
(j) | This amount includes excess deferred income taxes primarily associated with Tax Reform Legislation of $375 million, of which $273 million is related to protected deferred income taxes to be recovered over the related property lives utilizing the average rate assumption method in accordance with IRS normalization principles and $102 million related to unprotected (not subject to normalization) deferred income taxes to be amortized over a period approved by the Mississippi PSC or the FERC, as appropriate. Of the total excess deferred income taxes associated with Tax Reform Legislation, $129 million is associated with the Kemper County energy facility. The unprotected portion associated with the Kemper County energy facility is $54 million, of which $38 million is being amortized over eight years for retail as approved by the Mississippi PSC on February 6, 2018 and $16 million is wholesale-related. Currently, the Company is requesting eight-year amortization for the remaining portions of the unprotected deferred income taxes associated with Tax Reform Legislation in all of its retail and wholesale rate filings. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" and Note 5 for additional information. |
| |
(k) | Collected in advance from customers to remove assets upon their retirement. |
| |
(l) | For additional information, see Note 1 under "Provision for Property Damage." |
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" and "Kemper County Energy Facility" for additional information.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Government Grants
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants). Through December 31, 2017, the Company has received grant funds of $382 million, of which $245 million of the Initial DOE Grants were used for the construction of the Kemper County energy facility, which is reflected in the Company's financial statements as a reduction to the Kemper County energy facility capital costs, and $137 million received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts. An additional $2 million is expected to be received for allowable costs through December 31, 2017. See Note 3 under "Kemper County Energy Facility – Schedule and Cost Estimate" for additional information.
Revenues
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually.
The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 19.3% of the Company's total operating revenues in2017 and are largely subject to rolling 10-year cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Except as described above for the Company's cost-based MRA electric tariff customers, the Company has a diversified base of customers and no single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
See Note 3 under "Retail Regulatory Matters" for additional information.
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The Company's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Generation | $ | 2,801 |
| | $ | 2,632 |
|
Transmission | 737 |
| | 712 |
|
Distribution | 946 |
| | 916 |
|
General | 204 |
| | 520 |
|
Plant acquisition adjustment | 85 |
| | 85 |
|
Total plant in service | $ | 4,773 |
| | $ | 4,865 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for a portion of the railway track maintenance costs. The portion of railway track maintenance costs not charged to operations and maintenance expenses are charged to fuel stock and recovered through the Company's fuel clause.
Depreciation, Depletion, and Amortization
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.7% in 2017, 4.2% in 2016, and 4.7% in 2015. The decrease in 2017 is primarily due to lower depreciation expense as a result of recording a loss on the lignite mine in June 2017. The decrease in the 2016 depreciation rate is primarily due to fully depreciating and retiring the ARO at Plant Watson, partially offset by the increase in depreciation for the Plant Daniel scrubbers for a full year. See "Asset Retirement Obligations and Other Costs of Removal" herein for additional information. Depreciation studies are conducted periodically to update the composite rates. The Mississippi PSC approved the 2014 study, with new rates effective January 1, 2015. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities, except for the Kemper County energy facility combined cycle and related assets in service.
Asset Retirement Obligations and Other Costs of Removal
AROs are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
The liability for AROs primarily relates to facilities that are subject to the Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015 (CCR Rule), principally ash ponds. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Details of the AROs included in the balance sheets are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Balance at beginning of year | $ | 179 |
| | $ | 177 |
|
Liabilities incurred | — |
| | 15 |
|
Liabilities settled | (23 | ) | | (23 | ) |
Accretion | 5 |
| | 5 |
|
Cash flow revisions | 13 |
| | 5 |
|
Balance at end of year | $ | 174 |
| | $ | 179 |
|
The increase in cash flow revisions in 2017 is primarily related to a revision in the closure date of the lignite mine ARO.
The cost estimates for AROs related to the CCR Rule are based on information as of December 31, 2017 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements for closure. As further analysis is performed and closure details are developed, the Company will continue to periodically update these cost estimates as necessary.
Allowance for Funds Used During Construction
The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.7%, 6.5%, and 5.99% for the years ended December 31, 2017, 2016, and 2015, respectively. AFUDC equity was $72 million, $124 million, and $110 million in 2017, 2016, and 2015, respectively. The decrease in 2017 resulted from the Kemper IGCC project suspension in June 2017.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
Provision for Property Damage
The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, the MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. The Company made retail accruals of $3 million, $4 million, and $3 million for 2017, 2016, and 2015, respectively. The Company also accrued $0.3 million annually in 2017, 2016, and 2015 for the wholesale jurisdiction. As of December 31, 2017, the property damage reserve balances were $56 million and $1 million for retail and wholesale, respectively.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as used, at weighted-average cost when utilized.
Fuel Inventory
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel costs are recorded to inventory when purchased, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from the fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Fuel and interest rate derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel-hedging program as discussed below result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives.
The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company's collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 are immaterial.
The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income.
Variable Interest Entities
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company was required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper County energy facility. Liberty Fuels qualified as a VIE for which the Company was the primary beneficiary. As of December 31, 2016, the VIE consolidation resulted in an ARO asset and associated liability in the
NOTES (continued)
Mississippi Power Company 2017 Annual Report
amounts of $20 million and $24 million, respectively. As of December 31, 2017, the VIE consolidation resulted in an ARO liability in the amount of $38 million. The associated ARO asset was included as part of an additional charge to income in 2017 as a result of the Company's assessment of the probability of disallowance by the Mississippi PSC. See Note 3 under "Kemper County Energy Facility" for additional information.
2. RETIREMENT BENEFITS
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
|
| | | | | | | | |
Assumptions used to determine net periodic costs: | 2017 | | 2016 | | 2015 |
Pension plans | | | | | |
Discount rate – benefit obligations | 4.44 | % | | 4.69 | % | | 4.17 | % |
Discount rate – interest costs | 3.81 |
| | 3.97 |
| | 4.17 |
|
Discount rate – service costs | 4.83 |
| | 5.04 |
| | 4.49 |
|
Expected long-term return on plan assets | 7.95 |
| | 8.20 |
| | 8.20 |
|
Annual salary increase | 4.46 |
| | 4.46 |
| | 3.59 |
|
Other postretirement benefit plans | | | | | |
Discount rate – benefit obligations | 4.22 | % | | 4.47 | % | | 4.03 | % |
Discount rate – interest costs | 3.55 |
| | 3.66 |
| | 4.03 |
|
Discount rate – service costs | 4.65 |
| | 4.88 |
| | 4.38 |
|
Expected long-term return on plan assets | 6.88 |
| | 7.07 |
| | 7.23 |
|
Annual salary increase | 4.46 |
| | 4.46 |
| | 3.59 |
|
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 | | 2016 |
Pension plans | | | |
Discount rate | 3.80 | % | | 4.44 | % |
Annual salary increase | 4.46 |
| | 4.46 |
|
Other postretirement benefit plans | | | |
Discount rate | 3.68 | % | | 4.22 | % |
Annual salary increase | 4.46 |
| | 4.46 |
|
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of eight different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
|
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 5 |
| | $ | 5 |
|
Service and interest costs | — |
| | — |
|
Pension Plans
The total accumulated benefit obligation for the pension plans was $541 million at December 31, 2017 and $479 million at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 534 |
| | $ | 500 |
|
Service cost | 15 |
| | 13 |
|
Interest cost | 20 |
| | 19 |
|
Benefits paid | (22 | ) | | (20 | ) |
Actuarial (gain) loss | 55 |
| | 22 |
|
Balance at end of year | 602 |
| | 534 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 499 |
| | 430 |
|
Actual return (loss) on plan assets | 84 |
| | 39 |
|
Employer contributions | 2 |
| | 50 |
|
Benefits paid | (22 | ) | | (20 | ) |
Fair value of plan assets at end of year | 563 |
| | 499 |
|
Accrued liability | $ | (39 | ) | | $ | (35 | ) |
At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $571 million and $31 million, respectively. All pension plan assets are related to the qualified pension plan.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 158 |
| | $ | 154 |
|
Other current liabilities | (3 | ) | | (3 | ) |
Employee benefit obligations | (36 | ) | | (32 | ) |
Presented below are the amounts included in regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | | | | | |
| 2017 | | 2016 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 3 |
| | $ | 3 |
| | $ | — |
|
Net (gain) loss | 155 |
| | 151 |
| | 10 |
|
Regulatory assets | $ | 158 |
| | $ | 154 |
| | |
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Regulatory assets: | | | |
Beginning balance | $ | 154 |
| | $ | 144 |
|
Net (gain) loss | 12 |
| | 16 |
|
Change in prior service costs | — |
| | 2 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | (1 | ) | | (1 | ) |
Amortization of net gain (loss) | (7 | ) | | (7 | ) |
Total reclassification adjustments | (8 | ) | | (8 | ) |
Total change | 4 |
| | 10 |
|
Ending balance | $ | 158 |
| | $ | 154 |
|
Components of net periodic pension cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 15 |
| | $ | 13 |
| | $ | 13 |
|
Interest cost | 20 |
| | 19 |
| | 21 |
|
Expected return on plan assets | (40 | ) | | (35 | ) | | (33 | ) |
Recognized net (gain) loss | 7 |
| | 7 |
| | 10 |
|
Net amortization | 1 |
| | 1 |
| | 1 |
|
Net periodic pension cost | $ | 3 |
| | $ | 5 |
| | $ | 12 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 23 |
|
2019 | 24 |
|
2020 | 26 |
|
2021 | 27 |
|
2022 | 28 |
|
2023 to 2027 | 164 |
|
Other Postretirement Benefits
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2017 and 2016 were as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Change in benefit obligation | | | |
Benefit obligation at beginning of year | $ | 97 |
| | $ | 97 |
|
Service cost | 1 |
| | 1 |
|
Interest cost | 3 |
| | 3 |
|
Benefits paid | (6 | ) | | (6 | ) |
Actuarial (gain) loss | 1 |
| | 1 |
|
Retiree drug subsidy | 1 |
| | 1 |
|
Balance at end of year | 97 |
| | 97 |
|
Change in plan assets | | | |
Fair value of plan assets at beginning of year | 23 |
| | 23 |
|
Actual return (loss) on plan assets | 3 |
| | 1 |
|
Employer contributions | 4 |
| | 4 |
|
Benefits paid | (5 | ) | | (5 | ) |
Fair value of plan assets at end of year | 25 |
| | 23 |
|
Accrued liability | $ | (72 | ) | | $ | (74 | ) |
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 18 |
| | $ | 21 |
|
Other regulatory liabilities, deferred | (1 | ) | | (2 | ) |
Employee benefit obligations | (72 | ) | | (74 | ) |
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Approximately $17 million and $19 million was included in net regulatory assets at December 31, 2017 and 2016, respectively, related to the net loss for the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is $1 million.
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2017 and 2016 are presented in the following table:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Net regulatory assets (liabilities): | | | |
Beginning balance | $ | 19 |
| | $ | 18 |
|
Net (gain) loss | (1 | ) | | 2 |
|
Reclassification adjustments: | | | |
Amortization of net gain (loss) | (1 | ) | | (1 | ) |
Total reclassification adjustments | (1 | ) | | (1 | ) |
Total change | (2 | ) | | 1 |
|
Ending balance | $ | 17 |
| | $ | 19 |
|
Components of the other postretirement benefit plans' net periodic cost were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Service cost | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 3 |
| | 3 |
| | 4 |
|
Expected return on plan assets | (1 | ) | | (1 | ) | | (2 | ) |
Net amortization | 1 |
| | 1 |
| | 1 |
|
Net periodic postretirement benefit cost | $ | 4 |
| | $ | 4 |
| | $ | 4 |
|
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows:
|
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts | | Total |
| (in millions) |
2018 | $ | 6 |
| | $ | — |
| | $ | 6 |
|
2019 | 6 |
| | — |
| | 6 |
|
2020 | 6 |
| | (1 | ) | | 5 |
|
2021 | 7 |
| | (1 | ) | | 6 |
|
2022 | 7 |
| | (1 | ) | | 6 |
|
2023 to 2027 | 34 |
| | (2 | ) | | 32 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targeted mix of assets for each plan, is presented below:
|
| | | | | | | | |
| Target | | 2017 | | 2016 |
Pension plan assets: | | | | | |
Domestic equity | 26 | % | | 31 | % | | 29 | % |
International equity | 25 |
| | 25 |
| | 22 |
|
Fixed income | 23 |
| | 24 |
| | 29 |
|
Special situations | 3 |
| | 1 |
| | 2 |
|
Real estate investments | 14 |
| | 13 |
| | 13 |
|
Private equity | 9 |
| | 6 |
| | 5 |
|
Total | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | |
Domestic equity | 21 | % | | 25 | % | | 23 | % |
International equity | 21 |
| | 20 |
| | 18 |
|
Domestic fixed income | 37 |
| | 38 |
| | 43 |
|
Special situations | 2 |
| | 1 |
| | 2 |
|
Real estate investments | 12 |
| | 11 |
| | 10 |
|
Private equity | 7 |
| | 5 |
| | 4 |
|
Total | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2017 and 2016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management
NOTES (continued)
Mississippi Power Company 2017 Annual Report
relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 113 |
| | $ | 55 |
| | $ | — |
| | $ | — |
| | $ | 168 |
|
International equity(*) | 73 |
| | 66 |
| | — |
| | — |
| | 139 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 40 |
| | — |
| | — |
| | 40 |
|
Corporate bonds | — |
| | 56 |
| | — |
| | — |
| | 56 |
|
Pooled funds | — |
| | 31 |
| | — |
| | — |
| | 31 |
|
Cash equivalents and other | 10 |
| | 1 |
| | — |
| | — |
| | 11 |
|
Real estate investments | 22 |
| | — |
| | — |
| | 56 |
| | 78 |
|
Special situations | — |
| | — |
| | — |
| | 9 |
| | 9 |
|
Private equity | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Total | $ | 218 |
| | $ | 249 |
| | $ | — |
| | $ | 97 |
| | $ | 564 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 95 |
| | $ | 44 |
| | $ | — |
| | $ | — |
| | $ | 139 |
|
International equity(*) | 58 |
| | 51 |
| | — |
| | — |
| | 109 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 28 |
| | — |
| | — |
| | 28 |
|
Mortgage- and asset-backed securities | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Corporate bonds | — |
| | 46 |
| | — |
| | — |
| | 46 |
|
Pooled funds | — |
| | 25 |
| | — |
| | — |
| | 25 |
|
Cash equivalents and other | 47 |
| | — |
| | — |
| | — |
| | 47 |
|
Real estate investments | 15 |
| | — |
| | — |
| | 54 |
| | 69 |
|
Special situations | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Private equity | — |
| | — |
| | — |
| | 26 |
| | 26 |
|
Total | $ | 215 |
| | $ | 195 |
| | $ | — |
| | $ | 88 |
| | $ | 498 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 4 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
International equity(*) | 3 |
| | 2 |
| | — |
| | — |
| | 5 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 9 |
| | $ | 12 |
| | $ | — |
| | $ | 3 |
| | $ | 24 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Mississippi Power Company 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 4 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
International equity(*) | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 5 |
| | — |
| | — |
| | 5 |
|
Corporate bonds | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Real estate investments | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 9 |
| | $ | 12 |
| | $ | — |
| | $ | 3 |
| | $ | 24 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
Employee Savings Plan
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary. Total matching contributions made to the plan for 2017, 2016, and 2015 were $5 million each year.
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
Environmental Matters
Environmental Remediation
The Company must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up affected sites. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through established regulatory mechanisms. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
FERC Matters
Municipal and Rural Associations Tariff
The Company provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term cost-based, FERC regulated MRA tariff.
In March 2016, the Company reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities and has been recorded as a charge to income.
On September 18, 2017, the Company and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which the Company and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC on October 31, 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of the Company's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in the Company's revenues is not expected to be significant through 2020.
Fuel Cost Recovery
The Company has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At December 31, 2017, over-recovered wholesale MRA fuel costs were immaterial and at December 31, 2016 were approximately $13 million, and is included in over-recovered regulatory clause liabilities, current in the balance sheet. Effective January 1, 2018, the wholesale MRA fuel rate increased $11 million annually.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Market-Based Rate Authority
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies (including the Company) and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' (including the Company's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including the Company) and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies (including the Company) and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' (including the Company's) and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies (including the Company) and in
NOTES (continued)
Mississippi Power Company 2017 Annual Report
some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' (including the Company's) and Southern Power's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including the Company's) and Southern Power's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including the Company) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies (including the Company) and Southern Power responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided InterestCooperative Energy Power Supply Agreement
In 2008, the Company entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to SMEPA
In 2010 and as amended in 2012,86 MWs. On February 5, 2018, the Company and SMEPA entered intoCooperative Energy executed an agreement whereby SMEPA agreedamendment to extend the PSA through March 31, 2021, effective April 1, 2018, with increased total capacity of 286 MWs.
Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Company's transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS amended the terms of the NITSA on January 12, 2018 to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021. This NITSA amendment remains subject to acceptance by the FERC. The ultimate outcome of these matters cannot be determined at this time.
Retail Regulatory Matters
General
In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi.
In 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a 15% undivided interestuniform formula rate plan for the Company and other regulated electric utilities in Mississippi.
On January 26, 2018, the Mississippi PSC issued an order directing utilities to file within 30 days information regarding the impact on rates resulting from Tax Reform Legislation. The Company's Kemper County energy facility rates, approved on February 6, 2018, include the effects of Tax Reform Legislation. The Company's 2018 ECO, revised 2018 PEP, and 2018 SRR rate filings, all submitted in February 2018, include the effects of Tax Reform Legislation and are subject to approval by the Mississippi PSC.
The ultimate outcome of these matters cannot be determined at this time.
Performance Evaluation Plan
The Company's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the MPUS disputed certain items in the Kemper IGCC. On May 20, 2015, SMEPA notified2010 PEP lookback filing. In 2012, the Company that it was terminatingMississippi PSC issued an order canceling the agreement.Company's PEP lookback filing for 2011. In 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. Unresolved matters related to the 2010 PEP lookback filing, which remain under review, also impact the 2012 PEP lookback filing.
In 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15 million, annually, effective March 19, 2013. The Company had previously received a total of $275may be entitled to $3 million of deposits from SMEPA that were returned by Southern Companyin additional revenues related to SMEPA, with interest of approximately $26 million, on June 3, 2015,2013 as a result of the termination, pursuantlate implementation of the 2013 PEP rate increase.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
In 2014, 2015, 2016, and 2017, the Company issuedsubmitted its annual PEP lookback filings for the prior years, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a promissory note$5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, the aggregate principal amountCompany submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of approximately $3014%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to Southernallow more time for review.
On February 7, 2018, the Company which matures December 1, 2017.revised its annual projected PEP filing for 2018 to reflect the impacts of Tax Reform Legislation. The revised filing requests an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. See Note 5 for additional information.
The In-Service Asset Proposalultimate outcome of these matters cannot be determined at this time.
Energy Efficiency
In 2013, the Mississippi PSC approved an energy efficiency and the related rates approvedconservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were extended by an order issued by the Mississippi PSC excluded any costs associated within July 2016, until the 15% undivided interest. The Company continues to evaluate its alternatives with respect to its investment andtime the related costs associated with the 15% undivided interest.
Bonus Depreciation
On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. Bonus depreciation was extended for qualified property placed in service over the next five years. The PATH Act allows for 50% bonus depreciation for 2015, 2016, and 2017; 40% bonus depreciation for 2018; and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extension of 50% bonus depreciation is expected to result in approximately $3 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2015 tax year and approximately $360 million for the 2016 tax year, which may not all be realized in 2016 due toMississippi PSC approves a projected net operating loss (NOL) on Southern Company's 2016 consolidated income tax return, and is dependent upon placing the remainder of the Kemper IGCC in service in 2016. See "Kemper IGCC Schedule and Cost Estimate" herein for additional information.comprehensive portfolio plan program. The ultimate outcome of this matter cannot be determined at this time.
Investment Tax CreditsOn July 6, 2017, the Mississippi PSC issued an order approving the Company's Energy Efficiency Cost Rider 2017 compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits toOn November 30, 2017, the Company submitted its Energy Efficiency Cost Rider 2018 compliance filing which included a small decrease in connection with the Kemper IGCC. These tax credits were dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. As a result of the schedule extension for the Kemper IGCC, the Phase II tax credits have been recaptured.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of the Company, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013, 2014, and 2015. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, the Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $423 million as of December 31, 2015. See "Bonus Depreciation" herein and Note 5 under "Unrecognized Tax Benefits" for additional information.annual retail revenues. The ultimate outcome of this matter cannot be determined at this time.
Environmental Compliance Overview Plan
In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which were placed in service in 2015. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. In 2014, the Company entered into a settlement agreement with the Sierra Club under which, among other things, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018 (and the units were retired in July 2016). The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015 (which occurred in April 2015) and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) no later than April 2016 (which occurred in February and March 2016, respectively) and begin operating those units solely on natural gas (which occurred in June and July 2016, respectively).
In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with Plant Watson and Plant Greene County, respectively, for amortization over five-year periods that began in July 2016 and July 2017, respectively. As a result, these decisions are not expected to have a material impact on the Company's financial statements.
In August 2016, the Mississippi PSC approved the Company's revised ECO plan filing for 2016, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing, along with related carrying costs.
On May 4, 2017, the Mississippi PSC approved the Company's ECO plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing, along with related carrying costs.
On February 14, 2018, the Company submitted its ECO plan filing for 2018, including the effects of Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million, primarily related to the carryforward from the prior year. Approximately $13 million of related revenue requirements in excess of the 2% maximum, along with related carrying costs, remains deferred for inclusion in the 2019 filing. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Fuel Cost Recovery
The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually. On January 12, 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which resulted in an annual revenue increase of approximately $55 million. On November 15, 2017, the Company filed its annual rate adjustment under the retail fuel cost recovery clause, requesting an additional increase of $39 million annually, which the Mississippi PSC approved on January 16, 2018 effective February 2018 through January 2019. At December 31, 2017, the amount of under-recovered retail fuel costs included in the balance sheet in customer accounts receivable was approximately $6 million compared to $37 million over recovered at December 31, 2016.
The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow.
Ad Valorem Tax Adjustment
The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On July 6, 2017, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.
System Restoration Rider
In February 2016, the Company submitted its 2016 SRR rate filing which proposed no changes to either the SRR rate or the annual property damage reserve accrual of $3 million annually. On February 3, 2017, the Company submitted its 2017 SRR rate filing, which proposed an increase in the property damage reserve accrual of $1 million. These filings were suspended by the Mississippi PSC for review.
On January 21, 2017, a tornado caused extensive damage to the Company's transmission and distribution infrastructure. Storm damage repairs were approximately $9 million. A portion of these costs was charged to the retail property damage reserve and was addressed in the 2018 SRR rate filing.
On February 1, 2018, the Company submitted its 2018 SRR rate filing, including the effects of Tax Reform Legislation, which proposed that the SRR rate remain at zero and the annual accrual for the property damage reserve be reduced to $2 million in 2018.
The ultimate outcome of these matters cannot be determined at this time. See Note 1 under "Provision for Property Damage" for additional information.
Storm Damage Cost Recovery
In connection with the damage associated with Hurricane Katrina, the Mississippi PSC authorized the issuance of system restoration bonds in 2006. In accordance with a Mississippi PSC order on January 24, 2017, the Company eliminated the applicable Storm Restoration Charge because the bond sinking fund managed by the Mississippi State Bond Commission is substantially funded.
Kemper County Energy Facility
Overview
The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, the Company constructed approximately 61 miles of CO2 pipeline infrastructure for the transport of captured CO2 for use in enhanced oil recovery.
Schedule and Cost Estimate
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion for the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general
NOTES (continued)
Mississippi Power Company 2017 Annual Report
exceptions (Cost Cap Exceptions). The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." The Company achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO2, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, the Company experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, the Company determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast had decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations had increased significantly since certification.
On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing the Company to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of the related costs (Kemper Settlement Docket). On June 28, 2017, the Company notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future. On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among the Company, the MPUS, and certain intervenors (Kemper Settlement Agreement).
At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants. In the aggregate, the Company had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.
Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, the Company recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasifier portions of the plant and lignite mine. During the third and fourth quarters of 2017, the Company recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below. Additional pre-tax cancellation costs, including mine and plant closure and contract termination costs, currently estimated at approximately $50 million to $100 million (excluding salvage), are expected to be incurred in 2018. The Company has begun efforts to dispose of or abandon the mine and gasifier-related assets.
Rate Recovery
Kemper Settlement Agreement
On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement. The Kemper Settlement Agreement provides for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which includes the impact of Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of the Company's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).
Under the Kemper Settlement Agreement, retail customer rates will reflect a reduction of approximately $26.8 million annually and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date. On February 12, 2018, the Company made the required compliance filing with the Mississippi PSC. The Kemper Settlement Agreement also requires (i) the CPCN for the Kemper County energy facility to be modified to limit it to natural gas combined cycle operation and (ii) the Company to file a reserve margin plan with the Mississippi PSC by August 2018.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
As of December 31, 2017, the balances associated with the Kemper County energy facility regulatory assets and liabilities were $114 million and $26 million, respectively.
As a result of the Mississippi PSC order on February 6, 2018, rate recovery for the Kemper County energy facility is resolved, subject to any future legal challenges.
2015 Rate Case
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the Company's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets.
In connection with the implementation of the In-Service Asset Rate Order and wholesale rates, the Company began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees over periods ranging from two years to 10 years. On July 6, 2017, the Mississippi PSC issued an order requiring the Company to establish a regulatory liability account to maintain current rates related to the Kemper County energy facility following the July 2017 completion of the amortization period for certain of these regulatory assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
Lignite Mine and CO2 Pipeline Facilities
The Company owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. The Company expects mine reclamation to begin in 2018. In addition to the obligation to fund the reclamation activities, the Company provided working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information.
In addition, the Company constructed the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO2. Denbury has the right to terminate the contract at any time because the Company did not place the Kemper IGCC in service by July 1, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against the Company was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that the Company and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that the Company and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches have unjustly enriched the Company and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; ask the Circuit Court to revoke any licenses or certificates authorizing the Company or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and the Company and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal. The Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on the Company's results of operations, financial condition, and liquidity. The Company intends to vigorously defend itself in this matter and the ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
On June 9, 2016, Treetop, Greenleaf CO2 Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against the Company, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint related to the cancelled CO2 contract with Treetop and alleged fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of the Company, Southern Company, and SCS and sought compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, the Company, and SCS moved to compel arbitration pursuant to the terms of the CO2 contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages. On December 28, 2017, the Company reached a settlement agreement with Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group and the arbitration was dismissed.
4. JOINT OWNERSHIP AGREEMENTS
The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company.
In August 2014, a decision was made to cease coal operations at Greene County Steam Plant and convert to natural gas no later than April 16, 2016. As a result, active construction projects related to these assets were cancelled in September 2014. Associated amounts in CWIP of $6 million, reflecting the Company's share of the costs, were subsequently transferred to regulatory assets. See Note 3 under "Retail Regulatory Matters-Environmental Compliance Overview Plan" for additional information.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
At December 31, 20152017, the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows:
| | Generating Plant | Company Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP | Company Ownership | | Plant in Service | | Accumulated Depreciation | | CWIP |
| | | (in millions) | | | | | (in millions) | | |
Greene County | | | | | | | | | | | | | | |
Units 1 and 2 | 40 | % | | $ | 152 |
| | $ | 56 |
| | $ | 13 |
| 40 | % | | $ | 164 |
| | $ | 55 |
| | $ | 1 |
|
Daniel | | | | | | | | | | | | | | |
Units 1 and 2 | 50 | % | | $ | 686 |
| | $ | 160 |
| | $ | 10 |
| 50 | % | | $ | 713 |
| | $ | 189 |
| | $ | 4 |
|
The Company's proportionate share of plant operating expenses is included in the statements of operations and the Company is responsible for providing its own financing.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
CurrentFederal Tax Reform Legislation
Following the enactment of Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Deferred Income Taxes
DetailsJobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax provisions are as follows:authorities in order to finalize its accounting. The ultimate impact of Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note 3 under "Regulatory Matters" for additional information.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Federal — | | | | | |
Current | $ | (768 | ) | | $ | (431 | ) | | $ | 23 |
|
Deferred | 704 |
| | 183 |
| | (343 | ) |
| (64 | ) | | (248 | ) | | (320 | ) |
State — | | | | | |
Current | (81 | ) | | 1 |
| | 5 |
|
Deferred | 73 |
| | (38 | ) | | (53 | ) |
| (8 | ) | | (37 | ) | | (48 | ) |
Total | $ | (72 | ) | | $ | (285 | ) | | $ | (368 | ) |
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current | $ | 194 |
| | $ | (31 | ) | | $ | (768 | ) |
Deferred | (753 | ) | | (60 | ) | | 704 |
|
| (559 | ) | | (91 | ) | | (64 | ) |
State — | | | | | |
Current | — |
| | (6 | ) | | (81 | ) |
Deferred | 27 |
| | (7 | ) | | 73 |
|
| 27 |
| | (13 | ) | | (8 | ) |
Total | $ | (532 | ) | | $ | (104 | ) | | $ | (72 | ) |
NOTES (continued)
Mississippi Power Company 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in millions) | (in millions) |
Deferred tax liabilities — | | | | | | |
Accelerated depreciation | $ | 1,618 |
| | $ | 1,068 |
| $ | 373 |
| | $ | 386 |
|
ECM under recovered | 13 |
| | — |
| |
Property basis difference | | 242 |
| | 852 |
|
Regulatory assets associated with AROs | 71 |
| | 19 |
| 34 |
| | 72 |
|
Pensions and other benefits | 30 |
| | 35 |
| 28 |
| | 49 |
|
Regulatory assets associated with employee benefit obligations | 66 |
| | 68 |
| 45 |
| | 70 |
|
Regulatory assets associated with the Kemper IGCC | 86 |
| | 62 |
| |
Regulatory assets associated with the Kemper County energy facility | | 31 |
| | 82 |
|
Regulatory assets associated with Plant Daniel | | 9 |
| | 13 |
|
Rate differential | 115 |
| | 89 |
| — |
| | 141 |
|
Federal effect of state deferred taxes | — |
| | 1 |
| 9 |
| | — |
|
Fuel clause under recovered | — |
| | 3 |
| |
Ad valorem over/under recovery | | 11 |
| | 14 |
|
Regulatory assets for Mercury and Air Toxics Standards compliance | | 11 |
| | 8 |
|
Other | 163 |
| | 52 |
| 11 |
| | 91 |
|
Total | 2,162 |
| | 1,397 |
| 804 |
| | 1,778 |
|
Deferred tax assets — | | | | | | |
Fuel clause over recovered | 51 |
| | — |
| — |
| | 26 |
|
Estimated loss on Kemper IGCC | 451 |
| | 631 |
| 722 |
| | 484 |
|
Pension and other benefits | 92 |
| | 92 |
| 62 |
| | 96 |
|
Federal NOL | | 40 |
| | 109 |
|
Property insurance | 25 |
| | 24 |
| 15 |
| | 27 |
|
Premium on long-term debt | 18 |
| | 21 |
| 7 |
| | 14 |
|
Unbilled fuel | 16 |
| | 15 |
| |
AROs | 71 |
| | 19 |
| 34 |
| | 72 |
|
Interest rate hedges | 4 |
| | 5 |
| |
Kemper rate factor - regulatory liability retail | — |
| | 108 |
| |
Property basis difference | 451 |
| | 263 |
| 70 |
| | — |
|
ECM over recovered | — |
| | 1 |
| |
Affirmative adjustments | | 31 |
| | — |
|
Regulatory liability associated with Tax Reform Legislation (not subject to normalization)
| | 27 |
| | — |
|
Deferred state tax assets | 152 |
| | 57 |
| 133 |
| | 113 |
|
Deferred federal tax assets | 48 |
| | — |
| — |
| | 31 |
|
Federal effect of state deferred taxes | 8 |
| | — |
| — |
| | 19 |
|
Other | 13 |
| | 15 |
| 32 |
| | 31 |
|
Total | 1,400 |
| | 1,251 |
| 1,173 |
| | 1,022 |
|
Total deferred tax liabilities, net | 762 |
| | 146 |
| |
Deferred state tax asset | — |
| | 34 |
| |
Accumulated deferred income taxes | $ | 762 |
| | $ | 180 |
| |
Valuation allowance (net of $35 million in federal benefit) | | 122 |
| | — |
|
Accumulated deferred income tax (assets)/liabilities
| | (247 | ) | | 756 |
|
On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentationThe implementation of deferred income taxes. The new guidance resulted in a reclassification from prepaid income taxes of $121 million with $105 million to non-currentTax Reform Legislation significantly reduced accumulated deferred income taxes, and $16 million to other deferred charges in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information.
The application ofpartially offset by bonus depreciation provisions in current tax law hasthe Protecting Americans from Tax Hikes Act. Tax Reform Legislation also significantly reduced tax-related regulatory assets and increased deferred tax liabilities related to accelerated depreciation in 2015 and 2014.tax-related regulatory liabilities.
At December 31, 20152017, the tax-related regulatory assets were $291$36 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
At December 31, 2015,2017, the tax-related regulatory liabilities were $8$376 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and unamortized ITCs.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
In accordance with regulatory requirements, deferred federal ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of operations. Credits for non-Kemper IGCCCounty energy facility related deferred ITCs amortized in this manner amounted to $1 million in each of 2015, 2014,2017, 2016, and 2013.2015.
At December 31, 2015,2017, the Company had state of Mississippi NOL carryforwards totaling approximately $3$2.8 billion, resulting in deferred tax assets of approximately $97$111 million. The NOLs will expire between 20332031 and 2035, but are expected to be fully utilized by 2028.2037.
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | (35.0 | )% | | (35.0 | )% | | (35.0 | )% | (35.0 | )% | | (35.0 | )% | | (35.0 | )% |
State income tax, net of federal deduction | (6.3 | ) | | (4.0 | ) | | (3.7 | ) | 0.6 |
| | (5.7 | ) | | (6.3 | ) |
Non-deductible book depreciation | 1.3 |
| | 0.1 |
| | 0.1 |
| 0.1 |
| | 0.7 |
| | 1.3 |
|
AFUDC-equity | (49.6 | ) | | (7.8 | ) | | (5.0 | ) | — |
| | (28.5 | ) | | (49.6 | ) |
Non-deductible equity portion on Kemper IGCC write-off | | 5.3 |
| | — |
| | — |
|
Tax Reform Legislation | | 11.9 |
| | — |
| | — |
|
Other | (2.9 | ) | | 0.1 |
| | (0.1 | ) | — |
| | — |
| | (2.9 | ) |
Effective income tax rate (benefit rate) | (92.5 | )% | | (46.6 | )% | | (43.7 | )% | (17.1 | )% | | (68.5 | )% | | (92.5 | )% |
The increasedecrease in the Company's 20152017 effective tax rate (benefit rate), as compared to 2014,2016, is primarily due to a decreasean increase in estimated losses associated with the Kemper IGCC, offset by a decrease in non-taxable AFUDC equity.equity, and a decrease due to the remeasurement of deferred income taxes resulting from Tax Reform Legislation. The increasedecrease in the Company's 20142016 effective tax rate (benefit rate), as compared to 2013,2015, is primarily due to an increase in estimated losses associated with the Kemper IGCC and an increase in non-taxable AFUDC equity.
Tax Reform Legislation reduced the corporate income tax rate from 35% to 21%. As a result of implementation, the Company restated future tax benefits/deductions recorded as deferred tax assets/liabilities to reflect the new rate. The implementation resulted in a $372 million increase in tax expense and a $375 million increase in regulatory liabilities.
In March 2016, the FASB issued ASU 2016-09, which changed the accounting for income taxes for share-based payment award transactions. Entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. The adoption of ASU 2016-09 did not have a material impact on the Company's overall effective tax rate. See Note 1 under "Recently Issued Accounting Standards" for additional information.
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Unrecognized tax benefits at beginning of year | $ | 165 |
| | $ | 4 |
| | $ | 6 |
| $ | 465 |
| | $ | 421 |
| | $ | 165 |
|
Tax positions increase from current periods | 32 |
| | 58 |
| | — |
| — |
| | 26 |
| | 32 |
|
Tax positions increase/(decrease) from prior periods | 224 |
| | 103 |
| | (2 | ) | |
Tax positions increase from prior periods | | 2 |
| | 18 |
| | 224 |
|
Tax positions decrease from prior periods | | (177 | ) | | — |
| | — |
|
Reductions due to settlements | | (290 | ) | | — |
| | — |
|
Balance at end of year | $ | 421 |
| | $ | 165 |
| | $ | 4 |
| $ | — |
| | $ | 465 |
| | $ | 421 |
|
The tax positions increase from current periods and prior periods for 2015 and 2014 relates to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for more information. The tax positions decrease from prior periods for 2013 relates primarily to the Company's compliance with final U.S. Treasury regulations that resulted in a tax accounting method change for repairs.
The impact on the Company's effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| (in millions) |
Tax positions impacting the effective tax rate | $ | (2 | ) | | $ | 4 |
| | $ | 4 |
|
Tax positions not impacting the effective tax rate | 423 |
| | 161 |
| | — |
|
Balance of unrecognized tax benefits | $ | 421 |
| | $ | 165 |
| | $ | 4 |
|
The tax positions impacting the effective tax rate for 2015 primarily relate to a graduated tax rate adjustment on the 2014 federal income tax return. The tax positions impacting the effective tax rate for 2014 and 2013 primarily relate to state income tax credits. The tax positions not impacting the effective tax rate for 2015 and 2014 relate to deductions for R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for more information.
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
The tax positions increases from current periods and prior periods for 2017, 2016 and 2015 relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility, as well as federal income tax benefits from deferred ITCs. The tax positions decrease from prior periods and reductions due to settlements for 2017 relate primarily to the settlement of R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
The impact on the Company's effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Tax positions impacting the effective tax rate | $ | — |
| | $ | 1 |
| | $ | (2 | ) |
Tax positions not impacting the effective tax rate | — |
| | 464 |
| | 423 |
|
Balance of unrecognized tax benefits | $ | — |
| | $ | 465 |
| | $ | 421 |
|
The tax positions not impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper County energy facility. See "Section 174 Research and Experimental Deduction" herein for additional information.
Accrued interest for unrecognized tax benefits was as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Interest accrued at beginning of year | $ | 3 |
| | $ | 1 |
| | $ | 1 |
| $ | 28 |
| | $ | 13 |
| | $ | 3 |
|
Interest accrued during the year | 6 |
| | 2 |
| | — |
| (28 | ) | | 15 |
| | 10 |
|
Balance at end of year | $ | 9 |
| | $ | 3 |
| | $ | 1 |
| $ | — |
| | $ | 28 |
| | $ | 13 |
|
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months.months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of the Company, reduced tax payments for 2015 and included in its 2013 and 2014 consolidated federal income tax returnshas reflected deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern CompanyCounty energy facility in its federal income tax calculations since 2013 and filed amended its 2008 through 2013 federal income tax returns for 2008 through 2013 to also include deductions for Kemper IGCC-related R&E expenditures.
The Kemper IGCC is based on first-of-a-kind technology, andsuch deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company believerecognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest.
6. FINANCING
Going Concern
The Company's financial statement presentation contemplates continuation of the Company as a going concern as a result of Southern Company's anticipated ongoing financial support of the Company. Specifically, the Company has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide the Company with loans and/or equity to fund the remaining indebtedness to mature and other cash needs over the next 12 months. As of December 31, 2017, the Company's current liabilities exceeded current assets by approximately $911 million primarily due to a significant$900 million unsecured term loan that matures on March 31, 2018. The Company expects to refinance the unsecured term loan with external security issuances and/or borrowings from financial institutions or Southern Company. To fund
NOTES (continued)
Mississippi Power Company 2017 Annual Report
the Company's capital needs over the next 12 months, the Company intends to utilize operating cash flows, external security issuances, lines of credit, bank term loans, equity contributions from Southern Company and, to the extent necessary, loans from Southern Company.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2017 and 2016 was as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Parent company loans | $ | — |
| | $ | 551 |
|
Senior notes | — |
| | 35 |
|
Bank term loans | 900 |
| | — |
|
Revenue bonds(*) | 90 |
| | 40 |
|
Capitalized leases | — |
| | 3 |
|
Unamortized debt issuance expense
| (1 | ) | | — |
|
Outstanding at December 31 | $ | 989 |
| | $ | 629 |
|
| |
(*) | Includes $50 million in revenue bonds classified as short term at December 31, 2017 that were remarketed in an index rate mode subsequent to December 31, 2017. Also includes $40 million in pollution control revenue bonds classified as short term since they are variable rate demand obligations supported by short-term credit facilities; however, the final maturity dates range from 2020 to 2028. |
Maturities through 2022 applicable to total long-term debt are as follows: $900 million in 2018, $125 million in 2019, and $270 million in 2021. For long-term debt, other than revenue bonds, there are no scheduled maturities for 2020 and 2022.
Parent Company Loans and Equity Contributions
At December 31, 2016, the Company had $551 million of outstanding promissory notes to Southern Company.
In February 2017, the Company amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, the Company borrowed an additional $40 million under a promissory note issued to Southern Company.
In June 2017, Southern Company made equity contributions totaling $1.0 billion to the Company. The Company used a portion of the plant costs qualify as deductible R&E expendituresproceeds to (i) prepay $300 million of the outstanding principal amount under Internal Revenue Code Section 174. The IRS is currently reviewingits $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the underlying support for the deduction, but has not completed its audit$591 million outstanding principal amount of these expenditures. Duepromissory notes to the uncertainty related to this tax position,Southern Company; and (iii) repay a $10 million short-term bank loan.
In September 2017, the Company had related unrecognized tax benefits associated with these R&E deductions of approximately $423 million and associated interest of $9 million as of December 31, 2015. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information regarding the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time.
6. FINANCING
Bank Term Loans
In April 2015, the Company entered into two short-termissued a floating rate bank loans with a maturity date of April 1, 2016promissory note to Southern Company in an aggregate principal amount of $475up to $150 million bearing interest based on one-month LIBOR. The proceeds of these loans were usedCompany borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the repaymentquarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note 5 under "Section 174 Research and Experimental Deduction" for additional information. At December 31, 2017, the Company had no outstanding promissory notes to Southern Company.
Bank Term Loans
In March 2017, the Company issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.
In June 2017, the Company used a portion of the proceeds from Southern Company equity contributions to prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loans in an aggregateloan, which matures on March 30, 2018, and to repay $10 million of the outstanding principal amount of $275 million, working capital,bank loans. See "Parent Company Loans and other general corporate purposes, including the Company’s ongoing construction program. The Company also amended three outstanding floating rate bank loansEquity Contributions" herein for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.more information.
At December 31, 2015, the Company hadThis unsecured term loan has a total of $900 million in bank loans outstanding including $475 million classified as notes payable and $425 million classified as securities due within one year. At December 31, 2014, the Company had $775 million in bank loans outstanding which are classified as securities due within one year.
These bank loans have covenantscovenant that limitlimits debt levels to 65% of total capitalization, as defined in the agreements.agreement. For purposes of these definitions,this definition, debt excludes any long-term debt payable to affiliated trusts and other hybrid securities, and any securitized debt relating to the securitization of certain costs of the Kemper IGCC.securities. At December 31, 2015,2017, the Company was in compliance with its debt limits.limit.
In August 2017, the Company repaid a $12.5 million short-term bank note.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
At December 31, 2017, the Company had a $900 million unsecured term loan outstanding, which was reflected in the statements of capitalization as securities due within one year. At December 31, 2016, the Company had a $1.2 billion unsecured term loan outstanding, which was reflected in the statements of capitalization as long-term debt.
Senior Notes
At December 31, 20152017 and 2014,2016, the Company had $1.1 billion$755 million and $790 million of senior notes outstanding.outstanding, respectively, which included senior notes due within one year. These senior notes are effectively subordinated to the secured debt of the Company. See "Plant Daniel Revenue Bonds" below for additional information regarding the Company's secured indebtedness.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Plant Daniel Revenue Bonds
In 2011, in connection with the Company's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, the Company assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. These bonds are secured by Plant Daniel Units 3 and 4 and certain related personal property. The bonds were recorded at fair value as of the date of assumption, or $346 million, reflecting a premium of $76 million. See "Assets Subject to Lien" herein for additional information.
Securities Due Within One Year
A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2015 and 2014 was as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Senior notes | $ | 300 |
| | $ | — |
|
Bank term loans | 425 |
| | 775 |
|
Capitalized leases | 3 |
| | 3 |
|
Outstanding at December 31 | $ | 728 |
| | $ | 778 |
|
Maturities through 2020 applicable to total long-term debt are as follows: $728 million in 2016, $614 million in 2017, $3 million in 2018, $128 million in 2019, and $10 million in 2020.
Pollution Control Revenue Bonds
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of pollution control revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 20152017 and 20142016 was $83 million.
Other Revenue Bonds
Other revenue bond obligations represent loans to the Company from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCCCounty energy facility and related facilities.
The Company had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 20152017 and 2014.2016. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt.
Capital Leases
In 2013, the Company entered into an agreement to sell the air separation unit for the Kemper IGCCCounty energy facility and also entered into a 20-year20-year nitrogen supply agreement. The nitrogen supply agreement was determined to be a sale/leaseback agreement, which resulted in a capital lease obligation of $74 million at December 31, 20152016. Following the suspension of the Kemper IGCC, the Company entered into an asset purchase and 2014 of $77 million and $80 million, respectively,settlement agreement in December 2017 with an annual interest rate of 4.9% for both years.the lessor, which terminated the capital lease obligation. There arewere no contingent rentals in the contract and a portion of the monthly payment specified in the agreement iswas related to executory costs for the operation and maintenance of the air separation unit and excluded from the minimum lease payments. The minimum lease payments for 20152017 were $7 million and will be $7 million each year thereafter. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service.
Other Obligations
In June 2015, the Company issued an 18-month floating rate promissory note to Southern Company bearing interest based on LIBOR plus 1.25%. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposits. In December 2015, the $301 million promissory note was amended, which among other things, changed the maturity date to December 1, 2017 and changed the interest rate to be based on one-month LIBOR plus 1.50%.million. See Note 3 under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA""Kemper County Energy facility" for additional information.
In November 2015, the Company issued a 25-month floating rate promissory note to Southern Company bearing interest based on an adjusted LIBOR rate. At December 31, 2015, the adjusted LIBOR rate was equal to the one-month LIBOR plus 1.50%. This
NOTES (continued)
Mississippi Power Company 2015 Annual Report
note was for an aggregate principal amount of up to $375 million. As of December 31, 2015 the Company had borrowed $275 million.
Assets Subject to Lien
The revenue bonds assumed in conjunction with the purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy the obligations of Southern Company or another of its other subsidiaries. See "Plant Daniel Revenue Bonds" herein for additional information.
On October 4, 2017, the Company executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The agreements grant Chevron a security interest in its co-generation assets, with a net book value of approximately $93 million, located at Chevron's refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of the Company's credit rating to below investment grade by two of the three rating agencies.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Outstanding Classes of Capital Stock
The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as "Cumulative Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The Company's preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company's common stock with respect to payment of dividends and voluntary or involuntary dissolution. The preferred stock and depositary preferred stock is subject to redemption at the option of the Company at a redemption price equal to 100% of the liquidation amount of the stock. Information for each outstanding series is in the table below:
| | Preferred Stock | Par Value/Stated Capital Per Share | | Shares Outstanding | | Redemption Price Per Share | Par Value/Stated Capital Per Share | | Shares Outstanding | | Redemption Price Per Share |
4.40% Preferred Stock | $ | 100 |
| | 8,867 |
| | $ | 104.32 |
| $ | 100 |
| | 8,867 |
| | $ | 104.32 |
|
4.60% Preferred Stock | $ | 100 |
| | 8,643 |
| | $ | 107.00 |
| $ | 100 |
| | 8,643 |
| | $ | 107.00 |
|
4.72% Preferred Stock | $ | 100 |
| | 16,700 |
| | $ | 102.25 |
| $ | 100 |
| | 16,700 |
| | $ | 102.25 |
|
5.25% Preferred Stock | $ | 25 |
| | 1,200,000 |
| | $ | 25.00 |
| |
5.25% Preferred Stock(*) | | $ | 100 |
| | 300,000 |
| | $ | 100.00 |
|
| |
(*) | There are 1,200,000 outstanding depositary shares, each representing one-fourth of a share of the 5.25% preferred stock. |
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
Bank Credit Arrangements
At December 31, 20152017, committed credit arrangements with banks were as follows:
| | Expires | | Executable Term-Loans | | Due Within One Year | | Executable Term Loans | | Expires Within One Year |
2016 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
2018 | | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
(in millions) | | (in millions) | | (in millions) | | (in millions) | | (in millions) | | (in millions) | | (in millions) |
$220 | | $220 | | $195 | | $30 | | $15 | | $45 | | $175 | |
$100 | | | $100 | | $100 | | $— | | $— | | $— | | $100 |
In November 2017, the Company amended certain of its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2017 to 2018.
Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. In connection therewith, the Company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of these bank credit arrangements require payment of commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal.
Most of these bank credit arrangements contain covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities and any securitized debt relating to the securitization of certain costs of the Kemper IGCC.securities.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
A portion of the $195$100 million unused credit with banks is allocated to provide liquidity support to the Company's pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 20152017 was $40 million. In addition, at December 31, 2017, the Company had approximately $50 million of fixed rate revenue bonds that were remarketed from a long-term interest rate mode to an index rate mode, subsequent to December 31, 2017.
At December 31, 20152017 and 2014,2016, there was no commercial paper debt outstanding.
At December 31, 2015,2017 and 2016, there was $500$4 million and $23 million, respectively, of short-term debt outstanding. At December 31, 2014, there was no short-term debt outstanding.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
7. COMMITMENTS
Fuel and Purchased Power Agreements
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2015, 2014,2017, 2016, and 2013,2015, the Company incurred fuel expense of $395 million, $343 million, and $443 million,$574 million, and $491 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
Coal commitments include a management fee associated with a 40-year management contract with Liberty Fuels related to the Kemper IGCC with the remaining amount as of December 31, 2015 of $38 million. Additional commitments for fuel will be required to supply the Company's future needs.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional electric operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
In addition, the Company has entered into various long-term commitments for the purchase of energy through PPAs associated with solar facilities. The energy related costs associated with PPAs are recovered through the fuel cost recovery clause.
Operating Leases
The Company has entered into operating leases with Southern Linc and third parties for the use of cellular tower space. These agreements have initial terms ranging from five to 10 years and renewal options of up to 20 years. The Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $3 million, $3 million, and $5 million $10 million,for 2017, 2016, and $10 million for 2015, 2014, and 2013, respectively.
The Company includes any step rents, fixed escalations, lease concessions, and Gulf Power have jointlyreasonably assured renewal periods in its computation of minimum lease payments.
Estimated minimum lease payments under operating leases at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | |
| | | | Affiliate Operating Leases(a) | | Non-Affiliate Operating Lease(b) | | Total |
| | | | (in millions) |
2018 | | | | $ | 2 |
| | $ | 1 |
| | $ | 3 |
|
2019 | | | | 2 |
| | 1 |
| | 3 |
|
2020 | | | | 2 |
| | 1 |
| | 3 |
|
2021 | | | | 2 |
| | — |
| | 2 |
|
2022 | | | | 2 |
| | — |
| | 2 |
|
2023 and thereafter | | | | 7 |
| | — |
| | 7 |
|
Total | | | | $ | 17 |
| | $ | 3 |
| | $ | 20 |
|
| |
(a) | Includes operating leases with affiliates primarily related to cellular towers. |
| |
(b) | Primarily includes railcar and fuel handling equipment leases for Plant Daniel. |
In addition to the above rental commitments, the Company entered into operating lease agreements for aluminum railcars for the transportation of coal at Plant Daniel.Daniel, which is jointly owned with Gulf Power. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of the lease term. The Company has one remaining operating lease which has 229 aluminum railcars. The Company and Gulf Power also havehas separate lease agreements for other railcars that do not contain a purchase option.
The Company's 50% share (50%) of the leases,lease costs, charged to fuel stock and recovered through the fuel cost recovery clause, was $1 million in 2017, $2 million in 2015, $32016, and $2 million in 2014, and $3 million in 2013. The Company's annual railcar lease payments for 2016 through 2017 will average approximately $1 million. The Company has no lease obligations for the period 2018 and thereafter.2015.
In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson.Daniel. The Company's 50% share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense annually from 20132015 through 2015;2017; however, those amounts were immaterial for the reporting period. The Company's annual lease payments through 2020 are expected
NOTES (continued)
Mississippi Power Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $2 million in 2015, $8 million in 2014, and $7 million in 2013 related to barges and tow/shift boats. The Company has no future lease commitments with respect to these barge transportation leases.2017 Annual Report
8. STOCK COMPENSATION
Stock-Based Compensation
Stock-based compensation primarily in the form of Southern Company stock optionsperformance share units and performance sharerestricted stock units may be granted through the Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. In 2015 and 2016, stock-based compensation consisted exclusively of performance share units. Beginning in 2017, stock-based compensation granted to employees includes restricted stock units in addition to performance share units. Prior to 2015, stock-based compensation also included stock options. As of December 31, 2015,2017, there were 231180 current and former employees participating in the stock option, and performance share unit, programs.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Stock Options
Through 2009, stock-based compensation granted to employees consisted exclusively of non-qualifiedand restricted stock options. The exercise price for stock options granted equaled the stock price of Southern Company common stock on the date of grant. Stock options vest on a pro rata basis over a maximum period of three years from the date of grant or immediately upon the retirement or death of the employee. Options expire no later than 10 years after the grant date. All unvested stock options vest immediately upon a change in control where Southern Company is not the surviving corporation. Compensation expense is generally recognized on a straight-line basis over the three-year vesting period with the exception of employees that are retirement eligible at the grant date and employees that will become retirement eligible during the vesting period. Compensation expense in those instances is recognized at the grant date for employees that are retirement eligible and through the date of retirement eligibility for those employees that become retirement eligible during the vesting period. In 2015, Southern Company discontinued the granting of stock options. As a result, stock-based compensation granted to employees in 2015 consisted exclusively of performance share units.
For the years ended December 31, 2014 and 2013, employees of the Company were granted stock options for 578,256 shares and 345,830 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014 and 2013 derived using the Black-Scholes stock option pricing model was $2.20 and $2.93, respectively.
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. As of December 31, 2015, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial.
The total intrinsic value of options exercised during the years ended December 31, 2015, 2014, and 2013 was $3 million, $5 million, and $3 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million, $2 million, and $1 million for the years ended December 31, 2015, 2014, and 2013, respectively. As of December 31, 2015, the aggregate intrinsic value for the options outstanding and options exercisable was $7 million and $5 million, respectively.unit programs.
Performance Share Units
From 2010 through 2014, stock-based compensation granted to employees included performance share units in addition to stock options. Beginning in 2015, stock-based compensation consisted exclusively of performance share units. Performance share units granted to employees vest at the end of a three-year performance period which equates to the requisite service period for accounting purposes.period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
The performance goal for allSouthern Company issues performance share units issued from 2010 through 2014 waswith performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers. For thesepeers, performance share units at the end of three years, active employees receive shareswith performance goals based on Southern Company's performance while retired employees receive a pro rata number of shares based on the actual months of service duringcumulative earnings per share (EPS) over the performance period, prior to retirement. and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
In 2015 and 2016, the EPS-based and ROE-based awards each represented 25% of the total target grant date fair value of the performance share unit awards granted. The remaining 50% of the total target grant date fair value consisted of TSR-based awards. Beginning in 2017, the total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
Beginning in 2015, Southern Company issued two additional types of performance share units to employees in addition to the TSR-based awards. These included performance share units with performance goals based on cumulative earnings per share (EPS) over the performance period and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period. The EPS-based and ROE-based awards each represent 25% of total target grant date fair value of the performance share unit awards granted. The remaining 50% of the target grant date fair value consists of TSR-based awards. In contrast to the Monte Carlo simulation model used to determine the fair value of the TSR-based awards, the fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. TheEmployees become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, issued in 2015, vest immediately upon the retirement
NOTES (continued)
Mississippi Power Company 2015 Annual Report
of the employee.retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, employees of the Company were granted performance share units of 53,909, 49,579,30,933, 62,435, and 36,769,53,909, respectively. The weighted average grant-date fair value of TSR-based performance share units granted during 2015, 2014,2017, 2016, and 2013,2015, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $46.41, $37.54,$49.24, $45.17, and $40.50,$46.41, respectively. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017, 2016, and 2015 was $47.77.$49.22, $48.84, and $47.77, respectively.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, total compensation cost for performance share units recognized in income was $2 million, $4 million, $2 million, and $2$4 million, respectively, with the related tax benefit also recognized in income of $2$1 million, $1 million, and $1$2 million, respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees areis recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2015, there was $1 million of2017, total unrecognized compensation cost related to performance share award units that will bewas immaterial.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
Restricted Stock Units
Beginning in 2017, stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a weighted-averageresult, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of approximately 19 months.retirement eligibility.
For the year ended December 31, 2017, employees of the Company were granted 13,260 restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.22.
For the year ended December 31, 2017, total compensation cost for restricted stock units and the related tax benefit also recognized in income was immaterial. As of December 31, 2017, total unrecognized compensation cost related to restricted stock units was immaterial.
Stock Options
In 2015, Southern Company discontinued the granting of stock options. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur no later than November 2024.
The compensation cost related to the grant of Southern Company stock options to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. Compensation cost and related tax benefits recognized in the Company's financial statements were not material for any year presented. As of December 31, 2017, all compensation cost related to stock option awards has been recognized.
The total intrinsic value of options exercised during the years ended December 31, 2017, 2016, and 2015 was $2 million, $4 million, and $3 million, respectively. No cash proceeds are received by the Company upon the exercise of stock options. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $1 million, $2 million, and $1 million for the years ended December 31, 2017, 2016, and 2015, respectively. Prior to the adoption of ASU 2016-09 in 2016, the excess tax benefits related to the exercise of stock options were recognized in the Company's financial statements with a credit to equity. Upon the adoption of ASU 2016-09, beginning in 2016, all tax benefits related to the exercise of stock options are recognized in income. As of December 31, 2017, the aggregate intrinsic value for the options outstanding and exercisable was $4 million.
9. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
As of December 31, 20152017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
|
Interest rate derivatives | | — |
| | 1 |
| | — |
| | 1 |
|
Cash equivalents | $ | 52 |
| | $ | — |
| | $ | — |
| | $ | 52 |
| 224 |
| | — |
| | — |
| | 224 |
|
Total | | $ | 224 |
| | $ | 3 |
| | $ | — |
| | $ | 227 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 47 |
| | $ | — |
| | $ | 47 |
| $ | — |
| | $ | 9 |
| | $ | — |
| | $ | 9 |
|
NOTES (continued)
Mississippi Power Company 2015 Annual Report
As of December 31, 20142016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
|
Interest rate derivatives | | — |
| | 3 |
| | — |
| | 3 |
|
Cash equivalents | $ | 115 |
| | $ | — |
| | $ | — |
| | $ | 115 |
| 206 |
| | — |
| | — |
| | 206 |
|
Total | | $ | 206 |
| | $ | 6 |
| | $ | — |
| | $ | 212 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| $ | — |
| | $ | 10 |
| | $ | — |
| | $ | 10 |
|
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for foreign currency derivatives are from observable market sources. See Note 10 for additional information on how these derivatives are used.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
As of December 31, 20152017 and 20142016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt: | | | |
2015 | $ | 2,537 |
| | $ | 2,413 |
|
2014 | $ | 2,320 |
| | $ | 2,382 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt: | | | |
2017 | $ | 2,086 |
| | $ | 2,076 |
|
2016 | $ | 2,979 |
| | $ | 2,922 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company.
10. DERIVATIVES
The Company is exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity.prices. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.
NOTES (continued)
Mississippi Power Company 2015 Annual Report
Energy-related derivative contracts are accounted for under one of the following methods:
Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of operations as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 20152017, the net volume of energy-related derivative contracts for natural gas positions totaled 3253 million mmBtu for the Company, with the longest hedge date of 20182021 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions.
In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 4 million mmBtu.
Interest Rate Derivatives
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to income.
NOTES (continued)
Mississippi Power Company 2017 Annual Report
At December 31, 20152017, there were nothe following interest rate derivatives outstanding.were outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2017 |
| (in millions) | | | | | | | | (in millions) |
Cash Flow Hedges of Existing Debt | $ | 900 |
| | 1-month LIBOR | | 0.79% | | March 2018 | | $ | 1 |
|
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 20162018 are $1$0.5 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2022.
Derivative Financial Statement Presentation and Amounts
At December 31, 2015The Company enters into energy-related and 2014, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | |
Energy-related derivatives: | Other current assets | $ | — |
| | $ | — |
| | Other current liabilities | $ | 29 |
| | $ | 26 |
|
| Other deferred charges and assets | — |
| | — |
| | Other deferred credits and liabilities | 18 |
| | 19 |
|
Total derivatives designated as hedging instruments for regulatory purposes | | $ | — |
| | $ | — |
| | | $ | 47 |
| | $ | 45 |
|
Energy-related derivatives not designated as hedging instruments were immaterial for 2015 and 2014.
The Company'sinterest rate derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contractsthat may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with counterparties.
At December 31, 20152017 and 2014,2016, the fair value of energy-related derivatives presented inand interest rate derivatives was reflected on the table above didbalance sheets as follows:
|
| | | | | | | | | | | | |
| 2017 | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 1 |
| $ | 6 |
| $ | 2 |
| $ | 6 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| 3 |
| 2 |
| 5 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 9 |
| $ | 4 |
| $ | 11 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Interest rate derivatives: | | | | |
Other current assets/Other current liabilities | $ | 1 |
| $ | — |
| $ | 2 |
| $ | — |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 |
| $ | — |
| $ | 3 |
| $ | — |
|
Gross amounts recognized | $ | 3 |
| $ | 9 |
| $ | 7 |
| $ | 11 |
|
Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
Net amounts recognized in the Balance Sheets | $ | 1 |
| $ | 7 |
| $ | 4 |
| $ | 8 |
|
Energy-related derivatives not have amounts availabledesignated as hedging instruments were immaterial for offset.2017 and 2016.
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
At December 31, 20152017 and 20142016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instrumentsderivatives designated as regulatory hedging instruments and deferred on the balance sheets were as follows:
| | | Unrealized Losses | | Unrealized Gains | Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| Balance Sheet Location | 2017 | | 2016 | | Balance Sheet Location | 2017 | | 2016 |
|
| | (in millions) | | (in millions) | | (in millions) | | (in millions) |
Energy-related derivatives: | Other regulatory assets, current | $ | (29 | ) | | $ | (26 | ) | | Other regulatory liabilities, current | $ | — |
| | $ | — |
| Other regulatory assets, current | $ | (5 | ) | | $ | (5 | ) | | Other current liabilities | $ | — |
| | $ | 1 |
|
| Other regulatory assets, deferred | (18 | ) | | (19 | ) | | Other regulatory liabilities, deferred | — |
| | — |
| Other regulatory assets, deferred | (2 | ) | | (3 | ) | | Other regulatory liabilities, deferred | — |
| | — |
|
Total energy-related derivative gains (losses) | | $ | (47 | ) | | $ | (45 | ) | | $ | — |
| | $ | — |
| | $ | (7 | ) | | $ | (8 | ) | | $ | — |
| | $ | 1 |
|
For theall years ended December 31, 2015, 2014, and 2013,presented, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of operations were immaterial.
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were immaterial.
There was no material ineffectiveness recorded in earnings for any period presented.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015,2017, the Company'sCompany had no collateral posted with its derivative counterparties was immaterial.counterparties.
At December 31, 2015,2017, the fair value of derivative liabilities with contingent features was $12$1 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $52$12 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES (continued)
Mississippi Power Company 20152017 Annual Report
11. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) After Dividends on Preferred Stock |
| (in millions) |
March 2015 | $ | 276 |
| | $ | 24 |
| | $ | 35 |
|
June 2015 | 275 |
| | 12 |
| | 49 |
|
September 2015 | 341 |
| | (66 | ) | | (21 | ) |
December 2015 | 246 |
| | (143 | ) | | (71 | ) |
| | | | | |
March 2014 | $ | 331 |
| | $ | (325 | ) | | $ | (172 | ) |
June 2014 | 311 |
| | 56 |
| | 62 |
|
September 2014 | 355 |
| | (349 | ) | | (195 | ) |
December 2014 | 246 |
| | (71 | ) | | (24 | ) |
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) After Dividends on Preferred Stock |
| (in millions) |
March 2017 | $ | 272 |
| | $ | (62 | ) | | $ | (20 | ) |
June 2017 | 303 |
| | (2,954 | ) | | (2,054 | ) |
September 2017 | 341 |
| | 51 |
| | 40 |
|
December 2017 | 271 |
| | (177 | ) | | (556 | ) |
| | | | | |
March 2016 | $ | 257 |
| | $ | (10 | ) | | $ | 11 |
|
June 2016 | 277 |
| | (28 | ) | | 2 |
|
September 2016 | 352 |
| | 9 |
| | 26 |
|
December 2016 | 277 |
| | (166 | ) | | (89 | ) |
As a result of the revisions to the cost estimate for the Kemper IGCC and its June 2017 suspension, the Company recorded total pre-tax charges to income for the estimated probable losses onrelated to the Kemper IGCC of $183$208 million ($113185 million after tax) in the fourth quarter 2015, $1502017, $34 million ($9321 million after tax) in the third quarter 2015, $232017, $3.0 billion ($2.1 billion after tax) in the second quarter 2017, $108 million ($1467 million after tax) in the first quarter 2017, $206 million ($127 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2015, $92016, and $53 million ($633 million after tax) in the first quarter 2015, $702016. See Note 3 under "Kemper County Energy Facility" for additional information.
As a result of Tax Reform Legislation, the Company recorded total income tax expense of $372 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, and $380 million ($235 million after tax) in the first quarter 2014.2017. See Note 3 under "Integrated Coal Gasification Combined Cycle"5 for additional information.
The Company's business is influenced by seasonal weather conditions.
SELECTED FINANCIAL AND OPERATING DATA 2011-20152013-2017
Mississippi Power Company 20152017 Annual Report
| | | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Operating Revenues (in millions) | $ | 1,138 |
| | $ | 1,243 |
| | $ | 1,145 |
| | $ | 1,036 |
| | $ | 1,113 |
| $ | 1,187 |
| | $ | 1,163 |
| | $ | 1,138 |
| | $ | 1,243 |
| | $ | 1,145 |
|
Net Loss After Dividends on Preferred Stock (in millions) | $ | (8 | ) | | $ | (329 | ) | | $ | (477 | ) | | $ | 100 |
| | $ | 94 |
| |
Net Income (Loss) After Dividends on Preferred Stock (in millions)(a) | | $ | (2,590 | ) | | $ | (50 | ) | | $ | (8 | ) | | $ | (329 | ) | | $ | (477 | ) |
Cash Dividends on Common Stock (in millions) | $ | — |
| | $ | — |
| | $ | 72 |
| | $ | 107 |
| | $ | 76 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 72 |
|
Return on Average Common Equity (percent)(a) | (0.34 | ) | | (15.43 | ) | | (24.28 | ) | | 7.14 |
| | 10.54 |
| (120.43 | ) | | (1.87 | ) | | (0.34 | ) | | (15.43 | ) | | (24.28 | ) |
Total Assets (in millions)(b)(c) | $ | 7,840 |
| | $ | 6,642 |
| | $ | 5,822 |
| | $ | 5,334 |
| | $ | 3,631 |
| $ | 4,866 |
| | $ | 8,235 |
| | $ | 7,840 |
| | $ | 6,642 |
| | $ | 5,822 |
|
Gross Property Additions (in millions) | $ | 972 |
| | $ | 1,389 |
| | $ | 1,773 |
| | $ | 1,665 |
| | $ | 1,206 |
| $ | 536 |
| | $ | 946 |
| | $ | 972 |
| | $ | 1,389 |
| | $ | 1,773 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 2,359 |
| | $ | 2,084 |
| | $ | 2,177 |
| | $ | 1,749 |
| | $ | 1,049 |
| $ | 1,358 |
| | $ | 2,943 |
| | $ | 2,359 |
| | $ | 2,084 |
| | $ | 2,177 |
|
Redeemable preferred stock | 33 |
| | 33 |
| | 33 |
| | 33 |
| | 33 |
| 33 |
| | 33 |
| | 33 |
| | 33 |
| | 33 |
|
Long-term debt(a)(b) | 1,886 |
| | 1,621 |
| | 2,157 |
| | 1,561 |
| | 1,096 |
| 1,097 |
| | 2,424 |
| | 1,886 |
| | 1,621 |
| | 2,157 |
|
Total (excluding amounts due within one year) | $ | 4,278 |
| | $ | 3,738 |
| | $ | 4,367 |
| | $ | 3,343 |
| | $ | 2,178 |
| $ | 2,488 |
| | $ | 5,400 |
| | $ | 4,278 |
| | $ | 3,738 |
| | $ | 4,367 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 55.1 |
| | 55.8 |
| | 49.9 |
| | 52.3 |
| | 48.2 |
| 54.6 |
| | 54.5 |
| | 55.1 |
| | 55.8 |
| | 49.9 |
|
Redeemable preferred stock | 0.8 |
| | 0.9 |
| | 0.7 |
| | 1.0 |
| | 1.5 |
| 1.3 |
| | 0.6 |
| | 0.8 |
| | 0.9 |
| | 0.7 |
|
Long-term debt(a)(b) | 44.1 |
| | 43.3 |
| | 49.4 |
| | 46.7 |
| | 50.3 |
| 44.1 |
| | 44.9 |
| | 44.1 |
| | 43.3 |
| | 49.4 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Customers (year-end): | | | | | | | | | | | | | | | | | | |
Residential | 153,158 |
| | 152,453 |
| | 152,585 |
| | 152,265 |
| | 151,805 |
| 153,115 |
| | 153,172 |
| | 153,158 |
| | 152,453 |
| | 152,585 |
|
Commercial | 33,663 |
| | 33,496 |
| | 33,250 |
| | 33,112 |
| | 33,200 |
| 33,992 |
| | 33,783 |
| | 33,663 |
| | 33,496 |
| | 33,250 |
|
Industrial | 467 |
| | 482 |
| | 480 |
| | 472 |
| | 496 |
| 452 |
| | 451 |
| | 467 |
| | 482 |
| | 480 |
|
Other | 175 |
| | 175 |
| | 175 |
| | 175 |
| | 175 |
| 173 |
| | 175 |
| | 175 |
| | 175 |
| | 175 |
|
Total | 187,463 |
| | 186,606 |
| | 186,490 |
| | 186,024 |
| | 185,676 |
| 187,732 |
| | 187,581 |
| | 187,463 |
| | 186,606 |
| | 186,490 |
|
Employees (year-end) | 1,478 |
| | 1,478 |
| | 1,344 |
| | 1,281 |
| | 1,264 |
| 1,242 |
| | 1,484 |
| | 1,478 |
| | 1,478 |
| | 1,344 |
|
|
| |
(a) | A significant loss to income was recorded by the Company related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. |
(b) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $9 million $11 million, $4 million, and $8$11 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b)(c) | A reclassification of deferred tax assets from Total Assets of $105 million $16 million, $36 million, and $34$16 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-17. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
SELECTED FINANCIAL AND OPERATING DATA 2011-20152013-2017 (continued)
Mississippi Power Company 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | | | | | | | | | | |
Residential | $ | 238 |
| | $ | 239 |
| | $ | 242 |
| | $ | 227 |
| | $ | 247 |
| $ | 257 |
| | $ | 260 |
| | $ | 238 |
| | $ | 239 |
| | $ | 242 |
|
Commercial | 256 |
| | 257 |
| | 266 |
| | 251 |
| | 263 |
| 285 |
| | 279 |
| | 256 |
| | 257 |
| | 266 |
|
Industrial | 287 |
| | 291 |
| | 289 |
| | 263 |
| | 276 |
| 321 |
| | 313 |
| | 287 |
| | 291 |
| | 289 |
|
Other | (5 | ) | | 8 |
| | 2 |
| | 6 |
| | 7 |
| (9 | ) | | 7 |
| | (5 | ) | | 8 |
| | 2 |
|
Total retail | 776 |
| | 795 |
| | 799 |
| | 747 |
| | 793 |
| 854 |
| | 859 |
| | 776 |
| | 795 |
| | 799 |
|
Wholesale — non-affiliates | 270 |
| | 323 |
| | 294 |
| | 256 |
| | 273 |
| 259 |
| | 261 |
| | 270 |
| | 323 |
| | 294 |
|
Wholesale — affiliates | 76 |
| | 107 |
| | 35 |
| | 16 |
| | 30 |
| 56 |
| | 26 |
| | 76 |
| | 107 |
| | 35 |
|
Total revenues from sales of electricity | 1,122 |
| | 1,225 |
| | 1,128 |
| | 1,019 |
| | 1,096 |
| 1,169 |
| | 1,146 |
| | 1,122 |
| | 1,225 |
| | 1,128 |
|
Other revenues | 16 |
| | 18 |
| | 17 |
| | 17 |
| | 17 |
| 18 |
| | 17 |
| | 16 |
| | 18 |
| | 17 |
|
Total | $ | 1,138 |
| | $ | 1,243 |
| | $ | 1,145 |
| | $ | 1,036 |
| | $ | 1,113 |
| $ | 1,187 |
| | $ | 1,163 |
| | $ | 1,138 |
| | $ | 1,243 |
| | $ | 1,145 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | | | | | | | | | | |
Residential | 2,025 |
| | 2,126 |
| | 2,088 |
| | 2,046 |
| | 2,162 |
| 1,944 |
| | 2,051 |
| | 2,025 |
| | 2,126 |
| | 2,088 |
|
Commercial | 2,806 |
| | 2,860 |
| | 2,865 |
| | 2,916 |
| | 2,871 |
| 2,764 |
| | 2,842 |
| | 2,806 |
| | 2,860 |
| | 2,865 |
|
Industrial | 4,958 |
| | 4,943 |
| | 4,739 |
| | 4,702 |
| | 4,586 |
| 4,841 |
| | 4,906 |
| | 4,958 |
| | 4,943 |
| | 4,739 |
|
Other | 40 |
| | 40 |
| | 40 |
| | 38 |
| | 39 |
| 39 |
| | 39 |
| | 40 |
| | 40 |
| | 40 |
|
Total retail | 9,829 |
| | 9,969 |
| | 9,732 |
| | 9,702 |
| | 9,658 |
| 9,588 |
| | 9,838 |
| | 9,829 |
| | 9,969 |
| | 9,732 |
|
Wholesale — non-affiliates | 3,852 |
| | 4,191 |
| | 3,929 |
| | 3,819 |
| | 4,010 |
| 3,672 |
| | 3,920 |
| | 3,852 |
| | 4,191 |
| | 3,929 |
|
Wholesale — affiliates | 2,807 |
| | 2,900 |
| | 931 |
| | 572 |
| | 649 |
| 2,024 |
| | 1,108 |
| | 2,807 |
| | 2,900 |
| | 931 |
|
Total | 16,488 |
| | 17,060 |
| | 14,592 |
| | 14,093 |
| | 14,317 |
| 15,284 |
| | 14,866 |
| | 16,488 |
| | 17,060 |
| | 14,592 |
|
Average Revenue Per Kilowatt-Hour (cents)(a): | | | | | | | | | | |
Average Revenue Per Kilowatt-Hour (cents)(*): | | | | | | | | | | |
Residential | 11.75 |
| | 11.26 |
| | 11.59 |
| | 11.09 |
| | 11.40 |
| 13.22 |
| | 12.68 |
| | 11.75 |
| | 11.26 |
| | 11.59 |
|
Commercial | 9.12 |
| | 8.99 |
| | 9.27 |
| | 8.60 |
| | 9.17 |
| 10.31 |
| | 9.82 |
| | 9.12 |
| | 8.99 |
| | 9.27 |
|
Industrial | 5.79 |
| | 5.89 |
| | 6.10 |
| | 5.59 |
| | 6.01 |
| 6.63 |
| | 6.38 |
| | 5.79 |
| | 5.89 |
| | 6.10 |
|
Total retail | 7.90 |
| | 7.97 |
| | 8.21 |
| | 7.70 |
| | 8.21 |
| 8.91 |
| | 8.73 |
| | 7.90 |
| | 7.97 |
| | 8.21 |
|
Wholesale | 5.20 |
| | 6.06 |
| | 6.76 |
| | 6.19 |
| | 6.52 |
| 5.53 |
| | 5.71 |
| | 5.20 |
| | 6.06 |
| | 6.76 |
|
Total sales | 6.80 |
| | 7.18 |
| | 7.73 |
| | 7.23 |
| | 7.66 |
| 7.65 |
| | 7.71 |
| | 6.80 |
| | 7.18 |
| | 7.73 |
|
Residential Average Annual Kilowatt-Hour Use Per Customer | 13,242 |
| | 13,934 |
| | 13,680 |
| | 13,426 |
| | 14,229 |
| 12,692 |
| | 13,383 |
| | 13,242 |
| | 13,934 |
| | 13,680 |
|
Residential Average Annual Revenue Per Customer | $ | 1,556 |
| | $ | 1,568 |
| | $ | 1,585 |
| | $ | 1,489 |
| | $ | 1,622 |
| $ | 1,680 |
| | $ | 1,697 |
| | $ | 1,556 |
| | $ | 1,568 |
| | $ | 1,585 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts) | 3,561 |
| | 3,867 |
| | 3,088 |
| | 3,088 |
| | 3,156 |
| 3,628 |
| | 3,481 |
| | 3,561 |
| | 3,867 |
| | 3,088 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | | | | | | | | | | |
Winter | 2,548 |
| | 2,618 |
| | 2,083 |
| | 2,168 |
| | 2,618 |
| 2,390 |
| | 2,195 |
| | 2,548 |
| | 2,618 |
| | 2,083 |
|
Summer | 2,403 |
| | 2,345 |
| | 2,352 |
| | 2,435 |
| | 2,462 |
| 2,322 |
| | 2,384 |
| | 2,403 |
| | 2,345 |
| | 2,352 |
|
Annual Load Factor (percent) | 60.6 |
| | 59.4 |
| | 64.7 |
| | 61.9 |
| | 59.1 |
| 63.1 |
| | 64.0 |
| | 60.6 |
| | 59.4 |
| | 64.7 |
|
Plant Availability Fossil-Steam (percent)(b) | 90.6 |
| | 87.6 |
| | 89.3 |
| | 91.5 |
| | 87.7 |
| 89.1 |
| | 91.4 |
| | 90.6 |
| | 87.6 |
| | 89.3 |
|
Source of Energy Supply (percent): | | | | | | | | | | | | | | | | | | |
Coal | 16.5 |
| | 39.7 |
| | 32.7 |
| | 22.8 |
| | 34.9 |
| 7.5 |
| | 8.0 |
| | 16.5 |
| | 39.7 |
| | 32.7 |
|
Oil and gas | 81.6 |
| | 55.3 |
| | 57.1 |
| | 63.9 |
| | 51.5 |
| 88.0 |
| | 84.9 |
| | 81.6 |
| | 55.3 |
| | 57.1 |
|
Purchased power — | | | | | | | | | | | | | | | | | | |
From non-affiliates | 0.4 |
| | 1.4 |
| | 2.0 |
| | 2.0 |
| | 1.4 |
| 0.5 |
| | (0.3 | ) | | 0.4 |
| | 1.4 |
| | 2.0 |
|
From affiliates | 1.5 |
| | 3.6 |
| | 8.2 |
| | 11.3 |
| | 12.2 |
| 4.0 |
| | 7.4 |
| | 1.5 |
| | 3.6 |
| | 8.2 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
|
| |
(a)(*) | The average revenue per kilowatt-hour (cents) is based on booked operating revenues and will not match billed revenue per kilowatt-hour.
|
(b) | Beginning in 2012, plant availability is calculated as a weighted equivalent availability. |
SOUTHERN POWER COMPANY
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Power Company and Subsidiary Companies 20152017 Annual Report
The management of Southern Power Company (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 20152017.
/s/ Oscar C. Harper, IVJoseph A. Miller
Oscar C. Harper, IVJoseph A. Miller
Chairman, President, and Chief Executive Officer
/s/ William C. Grantham
William C. Grantham
Senior Vice President, Chief Financial Officer, and Treasurer
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of
Southern Power Company and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Power Company and Subsidiary Companies (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014, and2016, the related consolidated statements of income, comprehensive income, common stockholder'sstockholders' equity, and cash flows for each of the three years in the period ended December 31, 2015. 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-508 to II-542) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on thesethe Company's financial statements based on our audits.
We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. OurAs part of our audits, included considerationwe are required to obtain an understanding of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements, assessingstatements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statement presentation.statements. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements (pages II-473 to II-500) present fairly, in all material respects, the financial position of Southern Power Company and Subsidiary Companies as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
We have served as the Company's auditor since 2002.
DEFINITIONS
|
| |
Term | Meaning |
Alabama Power | Alabama Power Company |
AOCI | Accumulated other comprehensive income |
ASC | Accounting Standards Codification |
Clean Air ActASU | Clean Air Act Amendments of 1990Accounting Standards Update |
CO2 | Carbon dioxide |
COD | Commercial operation date |
CWIP | Construction work in progress |
EMC | Electric Membership Corporation |
EPA | U.S. Environmental Protection Agency |
EPEFASB | El Paso Electric CompanyFinancial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
First Solar | First Solar, Inc. |
FPL | Florida Power & Light Company |
GAAP | U.S. generally accepted accounting principles |
Georgia Power | Georgia Power Company |
Gulf Power | Gulf Power Company |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
KWH | Kilowatt-hour |
LTSA | Long-term service agreement |
Mississippi Power | Mississippi Power Company |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
MW | Megawatt |
MWH | Megawatt hour |
NOX | Nitrogen oxide |
OCI | Other comprehensive income |
power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
PPA | Power purchase agreementagreements, as well as contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid |
PTC | Production tax credit |
S&P | Standard and Poor's Rating Services,S&P Global Ratings, a division of The McGraw Hill Companies,S&P Global Inc. |
SCE | Southern California Edison Company |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
SO2 | Sulfur dioxide |
Southern Company | The Southern Company |
Southern Company Gas | Southern Company Gas and its subsidiaries |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, SouthernLINC Wireless,Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
SouthernLINC WirelessSouthern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
SRETax Reform Legislation | Southern Renewable Energy, Inc. |
SRP | Southern Renewable Partnerships, LLC |
STR | Southern Turner Renewable Energy, LLC owned 90% by SREThe Tax Cuts and 10% by TREJobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
TRE | Turner Renewable Energy, LLC, a 10% partner with SRE |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power Company and Subsidiary Companies 20152017 Annual Report
OVERVIEW
Business Activities
Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. The Company continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, development and construction of new power plants,generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and electric cooperatives.other load-serving entities, as well as commercial and industrial customers. In general, the Company has constructedcommitted to the construction or acquiredacquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During 2015,2017, the Company acquired constructed, or commenced construction of approximately 1,682424 MWs of additional solar and wind facilities including sixand completed construction of, and placed in service, approximately 222 MWs of solar facilities. In addition, the Company continued development of its portfolio of wind projects located in Georgia, six solar projects located in California, one solar project located in Texas, and one wind project located in Oklahoma. Thecontinued expansion of the 345-MW Mankato natural gas facility. Subsequent to December 31, 2017, the Company also entered into an agreement to acquireacquired Gaskell West 1, which is an approximately 151-MW wind facility located in Oklahoma, contingent upon achieving certain construction and project milestones. In addition, a 20-MW solar facility located in California was acquired on February 11, 2016.facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
As of December 31, 2015,2017, the Company owned generating units totaling 9,595Company's generation fleet totaled 12,940 MWs of nameplate capacity in commercial operation after taking into consideration(including 5,152 MWs owned by its equity ownership percentage of the solar facilities.subsidiaries). The average remaining duration of the Company's total portfolio of wholesale contracts is approximately 1015 years, including the Company's renewable assets (biomass, solar, and wind), which have average contract coverage of approximately 21 years. The duration of these contracts reduces remarketing risk for the Company. With the inclusion of the PPAs and capacityinvestments associated with the solarrenewable and natural gas facilities currently under construction and the acquisitions of Calipatria Solar, LLC (Calipatria),which was acquired aftersubsequent to December 31, 2015,2017, the Company has an average investment coverage ratio of 91% through 2022 and Grant Wind, LLC (Grant Wind),89% through 2027.
The Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in March 2016, as well as other capacity and energy contracts, the Company has an averagemiddle of 75%2018. The ultimate outcome of its available demonstrated capacity covered for the next five years (through 2020) and an average of 70% of its available demonstrated capacity covered for the next 10 years (through 2025). this matter cannot be determined at this time.
The Company's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as the Company's ability to execute its acquisitiongrowth strategy and growth strategy.to develop and construct generating facilities. In addition, the Company's earnings may be impacted by the availability of federal and state solar ITCs and wind PTCs on its renewable energy projects, which could be impacted by current or future potential tax reform legislation. See FUTURE EARNINGS POTENTIAL – "Acquisitions""Acquisitions," "Construction Projects," and "Construction Projects""Income Tax Matters" herein for additional information.
Key Performance IndicatorsEffective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations.
To evaluate operating results and to ensure the Company's ability to meet its contractual commitments to customers, the Company continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, (Peak Season EFOR)contract availability, and contract availability. Peak Season EFOR defines the hours during peak demand times when the Company's generating units are not available due to forced outages (a low metric is optimal). Contract availability measures the percentage of scheduled hours delivered. The Company's actual performance in 2015 met or surpassed targets in these two key performance areas.net income.
Net income is the primary measure of the Company's financial performance. See RESULTS OF OPERATIONS herein for information on the Company's net income for 2015.financial performance.
Earnings
The Company's 20152017 net income was $215$1.1 billion, a $733 million increase from 2016, primarily attributable to $743 million related to the Tax Reform Legislation. Also contributing to the change were increases in operating expenses and interest expense related to the Company's growth strategy and continuous construction program, largely offset by increased renewable energy sales.
The Company's 2016 net income was $338 million, a $43$123 million, or 25%57%, increase from 2014.2015. The increase was primarily due to increased revenuesfederal income tax benefits from new PPAs, including solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increasedincreases in depreciation, and other operations and maintenance expenses primarily due to new solar and wind facilities and higher income taxes.
The Company's 2014 net income was $172 million, a $6 million, or 4%, increase from 2013. The increase was primarily due to a decrease in income taxes primarily as a result of federal ITCs for new plants placed in service in 2014 and an increase in energy revenue primarily related to new solar PPAs. This increase was partially offset by increased depreciation, other operations and maintenance expenses, and interest expense.
Benefitsexpense from ITCsdebt issuances, primarily related to the Company's acquisitionnew solar and construction of solar facilities significantly impacted the Company's net income in 2015, 2014, and 2013. See Note 5 to the financial statements under "Effective Tax Rate" for additional information.wind facilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Benefits from solar ITCs, related to the Company's acquisition and construction of new facilities, and wind PTCs, related to wind generation, significantly impacted the Company's net income in 2017 and 2016. The Company's net income in 2015 was also significantly impacted by solar ITCs. See Note 5 to the financial statements under "Effective Tax Rate" for additional information.
RESULTS OF OPERATIONS
A condensed statement of income follows:
| | | Amount | | Increase (Decrease) from Prior Year | Amount | | Increase (Decrease) from Prior Year |
| 2015 | | 2015 | | 2014 | 2017 | | 2017 | | 2016 |
| (in millions) | (in millions) |
Operating revenues | $ | 1,390 |
| | $ | (111 | ) | | $ | 226 |
| $ | 2,075 |
| | $ | 498 |
| | $ | 187 |
|
Fuel | 441 |
| | (155 | ) | | 122 |
| 621 |
| | 165 |
| | 15 |
|
Purchased power | 93 |
| | (78 | ) | | 65 |
| 149 |
| | 47 |
| | 9 |
|
Other operations and maintenance | 260 |
| | 23 |
| | 28 |
| 386 |
| | 32 |
| | 94 |
|
Depreciation and amortization | 248 |
| | 28 |
| | 45 |
| 503 |
| | 151 |
| | 104 |
|
Taxes other than income taxes | 22 |
| | — |
| | 1 |
| 48 |
| | 25 |
| | 1 |
|
Total operating expenses | 1,064 |
| | (182 | ) | | 261 |
| 1,707 |
| | 420 |
| | 223 |
|
Operating income | 326 |
| | 71 |
| | (35 | ) | 368 |
| | 78 |
| | (36 | ) |
Interest expense, net of amounts capitalized | 77 |
| | (12 | ) | | 15 |
| 191 |
| | 74 |
| | 40 |
|
Other income (expense), net | 1 |
| | (5 | ) | | 10 |
| 1 |
| | (5 | ) | | 5 |
|
Income taxes (benefit) | 21 |
| | 24 |
| | (49 | ) | (939 | ) | | (744 | ) | | (216 | ) |
Net income | 229 |
| | 54 |
| | 9 |
| 1,117 |
| | 743 |
| | 145 |
|
Less: Net income attributable to noncontrolling interests | 14 |
| | 11 |
| | 3 |
| 46 |
| | 10 |
| | 22 |
|
Net income attributable to the Company | $ | 215 |
| | $ | 43 |
| | $ | 6 |
| $ | 1,071 |
| | $ | 733 |
| | $ | 123 |
|
Operating Revenues
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues include sales from natural gas, biomass, solar, and windthe Company's generation facilities. To the extent the Company has unused capacity not contracted under a PPA, it may sell power into the wholesale market orand, to the extent the generation assets are part of the Intercompany Interchange Contract (IIC), as approved by the FERC, it may sell power into the power pool.
Natural Gas and Biomass Capacity and Energy Revenue |
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| | | (in millions) | | |
PPA capacity revenues | $ | 569 |
| | $ | 546 |
| | $ | 572 |
|
PPA energy revenues | 560 |
| | 638 |
| | 451 |
|
Total PPA revenues | 1,129 |
| | 1,184 |
| | 1,023 |
|
Revenues not covered by PPA | 252 |
| | 315 |
| | 246 |
|
Other revenues | 9 |
| | 2 |
| | 6 |
|
Total Operating Revenues | $ | 1,390 |
| | $ | 1,501 |
| | $ | 1,275 |
|
Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.Operating revenues for 2015 were $1.4 billion, reflecting a $111 million,Energy is generally sold at variable cost or 7%, decrease from 2014. The decrease in operating revenues was primarily dueis indexed to the following:
PPA capacity revenuesincreased $23 million ($50 million related to affiliates partially offset by $27 million related to non-affiliates), primarily due to a 1% increase in total MW capacity contracted associated with newpublished natural gas PPAs.
PPA energy revenues decreased $78 million due to a $141 million decrease primarily related to a 34% decrease in the average price of energy driven by lower natural gas prices passed through in fuel revenues, partially offset by a 13% increase in KWH sales. In addition, the decrease was partially offset by a $63 million increase in energy revenues from PPAs related to the Company's acquisitions of solar and wind facilities. Overall, total KWH sales under PPAs increased 15% in 2015 when compared to 2014.
Revenues not covered by PPA decreased $63 million primarily due to lower natural gas prices, partially offset by a 19% increase in non-PPA KWH sales.
Operating revenues in 2014 were $1.5 billion, reflecting a $226 million, or 18%, increase from 2013. The increase in operating revenues was primarily due to the following:
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
PPA capacity revenuesdecreased $26 million primarily due to a 4% decrease in total MW capacity contracted associated with contract expirations.
PPA energy revenuesincreased $187 million due to a $133 million increase primarily related to higher natural gas prices passed through in fuel revenues and a 27% increase in KWH sales. Also contributing to the increase was a $54 million increase in energy revenues related to the Company's acquisitions of solar facilities.
Revenues not covered by PPA increased $69 million primarily due to a 9% increase in non-PPA KWH sales and higher gas prices.
Wholesaleindices. Energy revenues will vary depending on the energy demand of the Company's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of the Company's energy. Increases and decreases in revenues under PPAs that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.
Capacity revenues are an integral component of the Company's natural gas and biomass PPAs and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
The Company's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy sold to the grid. As a result, the Company's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding the Company's PPAs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of the Company's operating revenues were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| | | (in millions) | | |
PPA capacity revenues | $ | 599 |
| | $ | 541 |
| | $ | 569 |
|
PPA energy revenues | 970 |
| | 694 |
| | 560 |
|
Total PPA revenues | 1,569 |
| | 1,235 |
| | 1,129 |
|
Non-PPA revenues | 494 |
| | 330 |
| | 252 |
|
Other revenues | 12 |
| | 12 |
| | 9 |
|
Total operating revenues | $ | 2,075 |
| | $ | 1,577 |
| | $ | 1,390 |
|
Operating revenues for 2017 were $2.1 billion, reflecting a $498 million, or 32%, increase from 2016. The increase in operating revenues was primarily due to the following:
PPA capacity revenuesincreased $58 million, or 11%, primarily due to additional customer capacity requirements, and a new PPA related to the Mankato natural gas facility acquired in late 2016.
PPA energy revenues increased $276 million, or 40%, primarily due to a $213 million increase in renewable energy sales arising from new solar and wind facilities and a $50 million increase in sales from existing natural gas PPAs primarily due to an $85 million increase in the average cost of fuel, partially offset by a $35 million decrease in the volume of KWHs sold primarily due to reduced customer load.
Non-PPA revenues increased $164 million, or 50%, primarily due to a $156 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as an $8 million increase in the price of energy in the wholesale markets.
Operating revenues for 2016 were $1.6 billion, reflecting a $187 million, or 13%, increase from 2015. The increase in operating revenues was primarily due to the following:
PPA capacity revenuesdecreased $28 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily as a result of PPA expirations and subsequent generation capacity remarketing into the short-term markets, partially offset by a $16 million increase in affiliate capacity revenues due to new PPAs.
PPA energy revenues increased $134 million primarily due to a $170 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $36 million in fuel revenues related to natural gas PPAs. Overall, total KWH sales under PPAs increased 7% in 2016 when compared to 2015.
Non-PPA revenues increased $78 million primarily due to a 23% increase in KWH sales. Underlying this increase was a $113 million increase in short-term sales to non-affiliates as a result of remarketing generation capacity from expired PPAs, partially offset by a $35 million decrease in power pool sales primarily associated with a reduction in capacity available for sale.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the single largest expenseexpenses for the Company. Additionally,In addition, the Company purchases a portion of its electricity needs from the wholesale market.market including the power pool. Details of the Company's generation and purchased power were as follows:
| | | Total KWHs | Total KWH % Change | Total KWHs | Total KWH % Change | Total KWHs | Total KWH % Change | Total KWHs | Total KWH % Change |
| 2015 | | 2014 | | 2017 | | 2016 | |
| (in billions) | | (in billions) | | (in billions of KWHs) |
Generation | 33 | | 27 | | 44 | | 37 | |
Purchased power | 2 | | 3 | | 5 | | 3 | |
Total generation and purchased power | 35 | 17% | 30 | 24% | 49 | 23% | 40 | 14% |
Total generation and purchased power (excluding solar, wind and tolling) | 21 | 5% | 20 | 9% | |
Total generation and purchased power, excluding solar, wind, and tolling agreements | | 28 | 22% | 23 | 10% |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The Company's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing the Company for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, any increase or decreasechanges in such fuel costs isare generally accompanied by an increase or decreasea corresponding change in related fuel revenues under the PPAs and doesdo not have a significant impact on net income. The Company is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by the Company (excluding its subsidiaries).Company.
Purchased power expenses will vary depending on demand, availability, and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by the Company, an affiliate companies,company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of the Company's fuel and purchased power expenses were as follows: | | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | | (in millions) | | | | | (in millions) | | |
Fuel | $ | 441 |
| | $ | 596 |
| | $ | 474 |
| $ | 621 |
| | $ | 456 |
| | $ | 441 |
|
Purchased power | 93 |
| | 171 |
| | 106 |
| 149 |
| | 102 |
| | 93 |
|
Total fuel and purchased power expenses | $ | 534 |
| | $ | 767 |
| | $ | 580 |
| $ | 770 |
| | $ | 558 |
| | $ | 534 |
|
In 2017, total fuel and purchased power expenses increased $212 million, or 38%, compared to 2016. Fuel expenseincreased $165 million, or 36%, primarily due to an $83 million increase associated with the volume of KWHs generated and an $82 million increase associated with the average cost of natural gas per KWH generated. Purchased power expense increased $47 million, or 46%, primarily due to a $37 million increase associated with the volume of KWHs purchased and an $11 million increase associated with the average cost of purchased power.
II-455In 2016, total fuel and purchased power expenses increased $24 million, or 4%, compared to 2015. Fuel expenseincreased $15 million, or 3%, primarily due to a $22 million increase associated with the volume of KWHs generated, partially offset by a $7 million decrease associated with the average cost of natural gas per KWH generated. Purchased power expense increased $9 million, or 10%, primarily due to a $53 million increase associated with the volume of KWHs purchased, partially offset by a $28 million decrease associated with the average cost of purchased power and a $16 million decrease associated with a PPA expiration.
Other Operations and Maintenance Expenses
In 2017, other operations and maintenance expenses increased $32 million, or 9%, compared to 2016. The increase was primarily due to increases of $56 million associated with new facilities, $21 million in business development and support expenses, and $6 million in employee compensation, all associated with the Company's overall growth. These increases were partially offset by decreases of $35 million associated with scheduled outage and maintenance expenses and $15 million in non-outage operations and maintenance expenses.
In 2016, other operations and maintenance expenses increased $94 million, or 36%, compared to 2015. The increase was primarily due to increases of $35 million associated with new plants placed in service in 2015 and 2016, $25 million associated with scheduled outage and maintenance expenses, and $21 million in business development and support expenses and $13 million in employee compensation all primarily associated with the Company's overall growth.
Depreciation and Amortization
In 2017, depreciation and amortization increased $151 million, or 43%, compared to 2016. In 2016, depreciation and amortization increased $104 million, or 42%, compared to 2015. These increases were primarily due to additional depreciation related to new solar, wind, and natural gas facilities placed in service. See Note 1 to the financial statements under "Depreciation" for additional information.
Taxes Other Than Income Taxes
In 2017, taxes other than income taxes were $48 million compared to $23 million in 2016. In 2016, taxes other than income taxes increased $1 million, or 5%, compared to 2015. The increases were primarily due to additional property taxes due to new facilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
In 2015, total fuel and purchased power expenses decreased $233 million, or 30%, compared to 2014. The decrease was primarily due to the following:
Fuel expensedecreased $155 million, or 26%, primarily due to a $228 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $73 million increase associated with the volume of KWHs generated.
Purchased power expense decreased $78 million, or 46%, primarily due to a $60 million decrease associated with the volume of KWHs purchased as well as an $18 million decrease associated with the average cost of purchased power.
In 2014, total fuel and purchased power expenses increased $187 million, or 32%, compared to 2013. The increase was primarily due to the following:
Fuel expenseincreased $122 million, or 26%, primarily due to a $91 million increase associated with the average cost of natural gas per KWH generated as well as a $31 million increase associated with the volume of KWHs generated.
Purchased power expenseincreased $65 million, or 61%, primarily due to a $33 million increase associated with the average cost of purchased power and a $32 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
In 2015, other operations and maintenance expenses increased $23 million, or 10%, compared to 2014. The increase was primarily due to increases of $11 million associated with new plants placed in service in 2014 and 2015, $10 million in business development and support services expenses, $5 million in transmission costs, and $3 million in employee compensation. These increases were partially offset by a $6 million decrease in generation maintenance expense.
In 2014, other operations and maintenance expenses increased $29 million, or 14%, compared to 2013. The increase was primarily due to an $11 million increase in other generation expenses primarily related to labor and repairs as well as an $8 million increase primarily as a result of increased business development costs and support services. Also contributing to the increase was a $7 million increase in costs related to new plants placed in service, and a $2 million increase in employee compensation.
Depreciation and Amortization
In 2015, depreciation and amortization increased $28 million, or 13%, compared to 2014. The increase was primarily related to new plants placed in service in 2014 and 2015.
In 2014, depreciation and amortization increased $45 million, or 26%, compared to 2013. The increase resulted primarily from $25 million associated with an increase in plant in service, $8 million related to equipment retirements resulting from accelerated outage work, and $6 million related to increased production at natural gas plants.
See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Depreciation" herein for additional information regarding the Company's ongoing review of depreciation estimates and change to component depreciation in 2014. See also Note 1 to the financial statements under "Depreciation" for additional information.
Interest Expense, Net of Amounts Capitalized
In 2015,2017, interest expense, net of amounts capitalized decreased $12increased $74 million, or 13%63%, compared to 2014.2016. The decreaseincrease was primarily due to an increase of $44 million in interest expense related to an increase in average outstanding long-term debt, primarily to fund the Company's growth strategy and continuous construction program, as well as a $14$30 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.
In 2016, interest expense, net of amounts capitalized increased $40 million, or 52%, compared to 2015. The increase was primarily due to an increase of $66 million in interest expense related to additional debt issued during 2016 primarily to fund the Company's growth strategy and continuous construction program, partially offset by a $26 million increase in capitalized interest associated with the construction of solar facilities, partially offset by an increase of $2 million in interest expense related to additional debt issued to fund the Company's growth strategy and continuous construction program.facilities.
In 2014, interest expense, net of amounts capitalized increased $15 million, or 20%, compared to 2013. The increase was primarily due to a $9 million decrease in capitalized interest resulting from the completion of Plants Spectrum and Campo Verde in 2013 and an increase of $5 million in interest expense related to senior notes.Other Income (Expense), Net
In 2015,2017, other income (expense), net decreased $5 million, or 83%, compared to 2014, which2016. In 2016, other income (expense), net increased $10$5 million compared to 2013. These changes were driven by2015. For 2017, the recognition of a $5amount includes $159 million bargain purchase gain recognizedfrom currency losses compared to $82 million from currency gains in 20142016, arising from a solar acquisition. Additionally, in 2013 net income attributable to noncontrolling intereststranslation of approximately $4 million was included in other income (expense), net.€1.1 billion euro-denominated fixed-rate notes into U.S. dollars, each fully offset by an equal amount on the foreign currency hedges that were reclassified from accumulated OCI into earnings. See Note 109 to the financial statements under "Foreign Currency Derivatives" for additional information on noncontrolling interests.regarding hedging.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Income Taxes (Benefit)
In 2015,2017, income taxes (benefit) increased $24tax benefit was $939 million compared to 2014.$195 million for 2016 of which $743 million is related to the Tax Reform Legislation under which the Company remeasured its accumulated deferred income taxes based on the new federal income tax rates. The remaining increase in tax benefit was primarily due to a $26an increase of $89 million increase associated with higher pre-tax earningsin PTCs from wind generation in 2017 and a $9 million increase resulting fromother state apportionment rate changes, partiallyincome taxes, significantly offset by a decrease in tax benefits from lower ITCs from solar plants placed in service.
In 2016, income tax benefit was $195 million compared to an $11expense of $21 million for 2015. The $216 million change was primarily due to an increase of $180 million in federal income tax benefits primarily related to ITCs for solar plants placed in service and PTCs from wind generation in 2015.
In 2014, income taxes (benefit) decreased $492016 and a $35 million compared to 2013. The decrease was primarily due to a $20 million increase in tax benefits primarily from federal ITCs for solar plants placed in service in 2014, a $20 million decrease associated withexpense related to lower pre-tax earnings in 2016.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and an $11 million reduction in deferred income taxes as a result ofNote 1 to the impact of state apportionment changesfinancial statements under "Income and beneficial changes in certain state incomeOther Taxes" for information on how the Company recognizes the tax laws.
Seebenefits related to federal ITCs and PTCs and Note 5 to the financial statements under "Effective Tax Rate" for additional information.
Effects of Inflation
The Company is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.
FUTURE EARNINGS POTENTIAL
General
The results of operations for the past three years are not necessarily indicative of the Company's future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's competitive wholesale business. These factors include: the Company's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in the Company's market areas; the successful remarketing of capacity as current contracts expire; and the Company's ability to execute its growth strategy, including successfully expandingsuccessful additional investments in renewable and other energy projects, and to develop and construct generating facilities.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. See "Income Tax Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements for additional information.
In September 2017, the Company began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization is expected to be substantially completed in the impactfirst quarter 2018. The Company is pursuing the sale of ITCs. a 33% equity interest in the newly-formed holding company owning these solar assets, which, if successful, is expected to close in the middle of 2018. The ultimate outcome of this matter cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Demand for electricity is partiallyprimarily driven by economic growth. Thethe pace of economic growth and electricity demandthat may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.
Other factors that could influence future earnings include weather, demand,transmission constraints, cost of generatinggeneration from units within the power pool, and operational limitations.
Power Sales Agreements
General
The Company has assumed or entered into PPAs with some of Southern Company's traditional electric operating companies, other investor ownedinvestor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load serving entities. Although some of the Company's PPAs are with the traditional operating companies or other regulated utilities, the Company's generating facilities are not in those companies' regulated rate basesload-serving entities, as well as commercial and the Company is not able to seek recovery from those companies' ratepayers for construction, repair, environmental compliance, or maintenance costs. The Company expects that the capacity payments in the Company's PPAs involving natural gas and biomass generating facilities will produce sufficient cash flows to cover such costs, pay debt service, and provide an equity return. However, the Company's overall profit will depend on numerous factors, including efficient operation of its generating facilities and demand under the Company's PPAs.industrial customers. The PPAs are expected to provide the Company with a stable source of revenue during their respective terms.
Many of the Company's PPAs have provisions that require the Company or the counterparty to post collateral or an acceptable substitute guarantee in the event that S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.
The Company is working to maintain and expand its share of the wholesale market.markets. The Company expects that additionalthere to be new demand for capacity that will begin to develop within some of its market areas in the 2016-20182018-2020 timeframe. The size of available demand and timing will vary across the wholesale markets. The Company calculates an investment coverage ratio for its generating assets based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. With the inclusion of the PPAs and capacityinvestments associated with the solarwind and natural gas facilities currently under construction and the acquisitions of Calipatria,Gaskell West 1 solar facility which was acquired aftersubsequent to December 31, 2015, and Grant Wind, which is expected to close in March 2016,2017, as well as other capacity and energy contracts, the Company has an average investment coverage ratio of 75% of its available demonstrated capacity covered for the next five years (through 2020)91% through 2022 and 89% through 2027, with an average remaining contract duration of 70% of its available demonstrated capacity covered for the next 10 years (through 2025).approximately 15 years. See "Acquisitions" and "Construction Projects" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Natural Gas and Biomass
The Company's electricity sales from natural gas and biomass generating units are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. The Company typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that the Company serve the customer's capacity and energy requirements from a combination of the customer's own generating units and from Company resources not dedicated to serve unit or block sales. The Company has rights to purchase power provided by the requirements customers' resources when economically viable.
As a general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing the Company for substantially all of the cost of fuel or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, the Company may be responsible for excess fuel costs. With respect to fuel transportation risk, most of the Company's PPAs provide that the counterparties are responsible for transporting the availability of fuel transportation to the particular generating facility.
Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce the Company's exposure to certain operation and maintenance costs, the Company has long-term service agreements (LTSA).LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.
Solar and Wind
The Company's electricity sales from solar and wind (renewables) generating facilities are also throughmade pursuant to long-term PPAs; however, these solar and wind PPAs but do not have a capacity charge. Instead, thecharge and customers either purchase the energy output of a dedicated renewable facility through an energy charge.charge or provide the Company a certain fixed price for the electricity sold to the grid. As a result, the Company's ability to recover fixed and variable operation and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Environmental Matters
The Company's operations are subject to extensive regulationregulated by state and federal environmental agencies underthrough a variety of statuteslaws and regulations governing environmental media, including air, water, land, and landprotection of other natural resources. Applicable statutes includeThe Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact results of operations, cash flows, and financial condition. Compliance costs may result from the Clean Air Act;installation of additional environmental controls. The ultimate impact of the Clean Water Act;environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the Comprehensive Environmental Response, Compensation,availability and Liability Act;cost of any deployed control technology, and the Resource Conservation and Recovery Act; the Toxic Substances Control Act; the Emergency Planning & Community Right-to-Know Act; the Endangered Species Act; the Migratory Bird Treaty Act; the Bald and Golden Eagle Protection Act; and related federal and state regulations. Compliance with possible additional federal outcome of pending and/or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect the Company.future legal challenges.
New or revised environmental legislation or regulations, such as requirements related to greenhouse gases or changes to existing statutes orlaws and regulations could affect many areas of the Company's operations. While theThe Company's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.regulations.
Since the Company's units are newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding aesthetic impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and operating any type of future electric generating facility. The impact of such statuteslaws and regulations on the Company and subsequent recovery through PPA provisions cannot be determined at this time.
Environmental StatutesLaws and Regulations
Air Quality
Each ofIn 2011, the states in whichEPA finalized the Company has fossil generation is subject to the requirements of the Cross StateCross-State Air Pollution Rule (CSAPR). and its NOX annual, NOX seasonal, and SO2 annual programs. CSAPR is an emissions trading program that limitsaddresses the impacts of the interstate transport of SO2 and nitrogen oxideNOX emissions from fossil fuel-fired power plants located in 28upwind states in two phases, with Phase I having begun in 2015 and Phase II beginning in 2017. On July 28, 2015,the eastern half of the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas, but rejected all other pending challengeson air quality in downwind states. The Company has fossil fuel-fired generation subject to the rule. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. On December 3, 2015,these requirements. In October 2016, the EPA published a proposed revision tofinal rule that revised the CSAPR seasonal NO
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
that would revise existing ozone-seasonX program, establishing more stringent NOX emissions budgets for nitrogen oxide in Alabama and would remove FloridaTexas. The EPA also removed North Carolina from the CSAPR program. The EPA proposes to finalize this rulemaking by summer 2016.NOX seasonal program and completely removed Florida from all CSAPR programs. Georgia's seasonal NOX budget remains unchanged. Increases in either future fossil fuel-fired generation or the cost of CSAPR allowances could have a negative financial impact on results of operations for the Company.
In 2012, the EPA published proposed revisions to the New Source Performance Standard (NSPS) for Stationary Combustion Turbines (CT). If finalized as proposed, the revisions would apply the NSPS to all new, reconstructed, and modified CTs (including CTs at combined cycle units), during all periods of operation, including startup and shutdown, and alter the criteria for determining when an existing CT has been reconstructed.
On June 12, 2015, the EPA published a final rule requiring certain states (including Alabama, Florida, Georgia, North Carolina, and Texas) to revise or remove the provisions of their State Implementation Plans (SIPs) relating to the regulation ofstate implementation plans (SIP) regulating excess emissions at industrial facilities, including fossil fuel-firedelectric generating facilities, during periods of startup, shut-down, or malfunction (SSM) by no later than November 22, 2016.
. The Company has developedstate excess emission rules provide necessary operational flexibility to affected units during periods of SSM and, continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with the currentif removed, could affect unit availability and proposed environmental requirements discussed above. The impacts of CSAPR, the NSPS for CTs, and the SSM rule on the Company cannot be determined at this time and will depend on the specific provisions of the proposed rules, the resolution of pending and future legal challenges, and/or the development and implementation of rules at the state level. These regulations could result in additional capital expendituresincreased operations and compliancemaintenance costs that could affect results of operations, cash flows, and financial condition if such costs are not recovered through PPAs. Further, if higher costs are recovered through regulated rates at other utilities, this could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.the Company.
Water Quality
The EPA's final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existingIn 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures at existing power plants and manufacturing facilities became effective in October 2014.order to minimize their effects on fish and other aquatic life. The effect of this final rule will dependregulation requires plant-specific studies to determine applicable measures to protect organisms that either get caught on the results of additional studies and implementation ofintake screens (impingement) or are drawn into the rule by regulators based on site-specific factors. National Pollutant Discharge Elimination System permits issued after July 14, 2018 must include conditions to implement and ensure compliance with the standards and protective measures required by the rule.cooling system (entrainment). The ultimate impact of this rule will also depend on the outcome of ongoing legal challengesthese plant-specific studies and cannotany additional protective measures required to be determined at this time.incorporated into each plant's National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors.
On November 3,In 2015, the EPA published a finalfinalized the steam electric effluent limitations guidelines (ELG) rule which imposes stringent technology-based requirementsthat set national standards for certain wastestreamswastewater discharges from steam electric power plants.generating units. The rule prohibits effluent discharges of certain wastestreams and imposes stringent arsenic, mercury, selenium, and nitrate/nitrite limits on scrubber wastewater discharges. The revised technology-based limits and compliance dates will be incorporated into future renewals of National Pollutant Discharge Elimination System permits at affected units and may require extensive modifications to existing wastewater management systems or the installation and operation of multiple technologies sufficientnew wastewater management systems. Compliance with the ELG rule is expected to ensure compliance with applicable new numeric wastewater compliance limits.require capital expenditures and increased operational costs. Compliance deadlines betweenapplicability dates range from November 1, 2018 andto December 31, 2023 will be establishedwith state environmental agencies' incorporating specific applicability dates in permitsthe NPDES permitting process based on information provided for each applicable wastestream.waste stream. The ultimate impact of these requirements will depend on pendingEPA has committed to a new rulemaking that could potentially revise the limitations and any future legal challenges, complianceapplicability dates and implementation of the final rule and cannot be determined atELG rule. The EPA expects to finalize this time.
These water quality regulations could resultrulemaking in additional capital expenditures and compliance costs. Also, results of operations, cash flows, and financial condition could be impacted if such costs are not recovered through PPAs. Based on a preliminary assessment of the impact of the proposed rules, the Company estimates compliance costs to be immaterial. Further, if higher costs are recovered through regulated rates at other utilities, this could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition.2020.
Global Climate Issues
On October 23, 2015, the EPA published two final actions that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final actions contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final action, known as the Clean Power Plan, establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA published a proposed federal plan and model rule that, when finalized, states can adopt or that would be put in place if a state either does not submit a state plan or its plan is not approved by the EPA. On February 9, 2016, the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for its review with the courts. The stay will remain in effect through the resolution of the litigation, whether resolved in the U.S. Court of Appeals for the District of Columbia Circuit or the U.S. Supreme Court.
These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through PPAs. Further, if higher
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
costs are recovered through regulated rates at other utilities, this could contribute to reduced demandIn 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for electricity,all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could negatively impact resultsnew generation projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of operations, cash flows,Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and financial condition. However, the ultimate financial and operational impactCorps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
Global Climate Issues
In 2015, the EPA published final rules onlimiting CO2 emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO2 emission performance standards for existing units (known as the Company cannot be determined at this timeClean Power Plan or CPP). In February 2016, the U.S. Supreme Court granted a stay of the CPP, which will remain in effect through the resolution of litigation in the U.S. Court of Appeals for the District of Columbia challenging the legality of the CPP and will depend upon numerous factors,any review by the U.S. Supreme Court. On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources, including the Company's ongoing review of the final rules;CPP and other CO2 emissions rules. On October 10, 2017, the outcomeEPA published a proposed rule to repeal the CPP and, on December 28, 2017, published an advanced notice of legal challenges, individual state implementation ofproposed rulemaking regarding a CPP replacement rule.
In 2015, parties to the EPA's final guidelines,United Nations Framework Convention on Climate Change, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
The United Nations 21st international climate change conference took place in late 2015. The result was the adoption ofStates, adopted the Paris Agreement, which establishesestablished a non-binding universal framework for addressing greenhouse gas (GHG) emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years.On June 1, 2017, the U.S. President announced that the United States would withdraw from the Paris Agreement and begin renegotiating its terms. The ultimate impact of this agreement or any renegotiated agreement depends on its ratification and implementation by participating countries and cannot be determined at this time.countries.
The EPA's greenhouse gasGHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO2 equivalent emissions in metric tons for a company's operational control of facilities. Based on ownership or financial control of facilities, the Company's 2014 greenhouse gas2016 GHG emissions were approximately 1113 million metric tons of CO2 equivalent. The preliminary estimate of the Company's 2015 greenhouse gas2017 GHG emissions on the same basis is approximately 13 million metric tons of CO2 equivalent. The level of greenhouse gas emissions from year to year will depend on the level of generation, the mix of fuel sources, and other factors.
Income Tax Matters
Consolidated Income Taxes
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined, unitary, or consolidated. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect the Company's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein and Note 5 to the financial statements for additional information.
The Company currently has unutilized federal ITC and PTC carryforwards totaling approximately $2.0 billion, and thus anticipates utilizing third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner will take significantly all of the respective federal tax benefits. These tax equity partnerships are expected to be consolidated in the Company's financial statements using a hypothetical liquidation at book value (HLBV) methodology to allocate partnership gains and losses to the Company.
Federal Tax CreditsReform Legislation
In 2009, President ObamaOn December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the American Recoveryfederal corporate income tax rate to 21%, retains normalization provisions for public utility property and Reinvestment Act of 2009 (ARRA). Major tax incentives in the ARRA includedexisting renewable energy incentives. Onincentives, and repeals the corporate alternative minimum tax.
For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down 20% each year until it completely phases out for qualified property placed in service after December 18, 2015,31, 2027. Further, the business interest deduction is
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforward, and depreciation and amortization through December 31, 2021 and thereafter to 30% of taxable income excluding interest and NOL carryforwards.
In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax benefit of $743 million, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Tax Credits
The Tax Reform Legislation retained the renewable energy incentives that were included in the Protecting Americans from Tax Hikes (PATH) Act was signed into law.Act. The PATH Act extended the ITC with a phase out that allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and thea permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act extended the production tax credit (PTC) for wind projects with a phase out that allows for 100% PTC for wind projects that commencecommenced construction in 2016; 80% PTC for wind projects that commencecommenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. The Company receiveshas received ITCs related to its investment in new solar facilities acquired or constructed and receives PTCs related to the first 10 years of energy production from its wind facility,facilities, which have had, and will continue to have, a material impact on the Company's cash flows and net income. At December 31, 2017, the Company had approximately $2.0 billion of unutilized ITCs and PTCs, which are currently expected to be fully utilized by 2027, but could be further delayed as a result of the Company's continued growth strategy, as well as the impacts from the Tax Reform Legislation. See Note 1 to the financial statements under "Income and Other Taxes" and Note 5 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information.information regarding utilization and amortization of credits and the tax benefit related to basis differences.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act also extended bonus depreciation for qualified property placed in service over the next five years. The PATH Act allowsallowed for 50% bonus depreciation for 2015 2016, and 2017;through 2017, 40% bonus depreciation for 2018;2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. The extensionBased on provisional estimates, approximately $130 million of 50%positive cash flows is expected to result from bonus depreciation for the 2017 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. In addition, any cash flows resulting from bonus depreciation will also be impacted by the Company's use of third-party tax equity arrangements. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of these matters cannot be determined at this time.
Legal Entity Reorganization
In September 2017, the Company began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in approximately $195estimated tax benefits totaling between $50 million of positive cash flows for the 2015 tax year and approximately $350$55 million for the 2016 tax year, which may not all be realizedrelated to certain changes in 2016 due to a projectedstate apportionment rates and net operating loss for tax purposes oncarryforward utilization that will be recorded in the Company's 2016 income tax return becausefirst quarter 2018. The Company is pursuing the sale of bonus depreciation.a 33% equity interest in the newly-formed holding company owning these solar assets. The ultimate outcome of this matter cannot be determined at this timetime.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Acquisitions
During 2015,2017 and subsequent to December 31, 2017, in accordance with the Company'sits overall growth strategy, the Company acquired or contracted to acquire through its wholly-owned subsidiaries, SRP or SRE, the projects set forth indiscussed below, as well as the following table. Acquisition-related costs were expensed as incurred and areCactus Flats wind facility discussed in the Company's "RESULTS OF OPERATIONS" herein, if significant.under "Construction Projects" herein. See Note 211 to the financial statements for additional information.
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Project Facility | Approx. Nameplate Capacity | Location | Percentage Ownership | | Expected/Actual COD | PPA Contract Period |
| (MW) | | | | | |
WIND |
Kay Wind | 299 | Kay County, OK | 100 | % | | December 12, 2015 | 20 years |
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Grant Wind(c) | 151 | Grant County, OK | 100 | % | | March 2016 | 20 years |
SOLAR |
Lost Hills Blackwell | 33 | Kern County, CA | 51 | % | (a) | April 17, 2015 | 29 years |
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North Star | 61 | Fresno County, CA | 51 | % | (a) | June 20, 2015 | 20 years |
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Tranquillity(d) | 205 | Fresno County, CA | 51 | % | (a) | Fourth quarter 2016 | 18 years |
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Desert Stateline(e) | 299 | San Bernardino County, CA | 51 | % | (a) | December 2015 to third quarter 2016 (f) | 20 years |
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Morelos | 15 | Kern County, CA | 90 | % | (b) | November 25, 2015 | 20 years |
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Roserock(g) | 160 | Pecos County, TX | 51 | % | (a) | Fourth quarter 2016 | 20 years |
| | | | | | |
Garland and Garland A(h) | 205 | Kern County, CA | 51 | % | (a) | Fourth quarter 2016 | 15 years and 20 years |
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Calipatria(i) | 20 | Imperial County, CA | 90 | % | (b) | February 11, 2016 | 20 years |
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Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual/Expected COD | PPA Counterparties | PPA Contract Period |
Business Acquisitions During the Year Ended December 31, 2017 |
Bethel | Wind | Invenergy Wind Global LLC, January 6, 2017 | 276 | Castro County, TX | 100% | | January 2017 | Google Energy, LLC | 12 years |
Asset Acquisitions Subsequent to December 31, 2017 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC, January 26, 2018 | 20 | Kern County, CA | 100% of Class B | (*) | March 2018 | Southern California Edison | 20 years |
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(a)(*) | The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federalinterest under a tax benefits with respect to the transaction. |
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(b) | The Company owns 90%, with the minority owner, TRE, owning 10%. |
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(c) | Grant Wind - On September 4, 2015, the Company entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The ultimate outcome of this matter cannot be determined at this time.
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(d) | Tranquillity - Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million. The ultimate outcome of this matter cannot be determined at this time.
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(e) | Desert Stateline - Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion. The ultimate outcome of this matter cannot be determined at this time.
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(f) | Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service.
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(g) | Roserock - Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million. The ultimate outcome of this matter cannot be determined at this time.
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(h) | Garlandand Garland A - Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million. The ultimate outcome of this matter cannot be determined at this time.
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(i) | Calipatria - On February 11, 2016, SRE and TRE acquired all of the outstanding membership interests of Calipatria. equity partnership agreement. |
The aggregate amount of revenue recognized by the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income for 2015 is $18 million. The aggregate amount of net income, excluding the impacts of ITCs, attributable to the Company related to the acquisitions, since the various acquisition dates, included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to their assets being constructed and placed in service; therefore, supplemental proforma information as though the acquisitions occurred as of the beginning of 2015 and for the comparable 2014 year is not meaningful and has been omitted.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Construction Projects
Construction Projects Completed and in Progress
During 2015,2017, in accordance with the Company'sits overall growth strategy, the Company constructedcompleted construction of and placed in service, or commencedcontinued construction of, the projects set forth in the table below,below.
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| | | | | | | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual / Expected COD | PPA Counterparties | PPA Contract Period |
Construction Projects Completed During the Year Ended December 31, 2017 |
East Pecos | Solar | 120 | | Pecos County, TX | 100 | % | | March 2017 | Austin Energy | 15 years |
Lamesa | Solar | 102 | | Dawson County, TX | 100 | % | | April 2017 | City of Garland, Texas | 15 years |
Projects Under Construction at December 31, 2017 |
Cactus Flats | Wind | 148 | | Concho County, TX | 100 | % | (*) | Third quarter 2018 | General Motors and General Mills | 12 years and 15 years |
Mankato Expansion | Natural Gas | 345 | | Mankato, MN | 100% |
| | Second quarter 2019 | Northern States Power Company | 20 years |
(*) On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in additionservice, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the Tranquillity, Desert Stateline, Roserock, Garland,class B membership interests.
Total aggregate construction costs for projects under construction at December 31, 2017, excluding acquisition costs and Garland A facilities. Total costincluding construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, total costs of construction incurred for these projects during 2015 was $1.8 billion,$188 million, all of which $1.1 billion remainsremained in CWIP at December 31, 2015. CWIP.
Development Projects
During 2017, as part of the Company's renewable development strategy, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
During 2016, the Company entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
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| | | | | | | | | | | |
Solar Facility | Approx. Nameplate Capacity | County Location in Georgia | Expected/Actual COD | PPA Contract Period | Estimated Construction Cost | |
| (MW) | | | | (in millions) | |
Sandhills | 146 | Taylor | Fourth quarter 2016 | 25 years | $ | 260 |
| - | 280 |
| |
Decatur Parkway | 84 | Decatur | December 31, 2015 | 25 years | Approx. $169 | (*) |
Decatur County | 20 | Decatur | December 29, 2015 | 20 years | Approx. $46 | (*) |
Butler | 103 | Taylor | Fourth quarter 2016 | 30 years | $ | 220 |
| - | 230 |
| (*) |
Pawpaw | 30 | Taylor | March 2016 | 30 years | $ | 70 |
| - | 80 |
| (*) |
Butler Solar Farm | 22 | Taylor | February 10, 2016 | 20 years | Approx. $45 | (*) |
| |
(*) | Includes the acquisition price of all outstanding membership interests of the respective development entity. |
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against the Companyor regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Revenue Recognition
The Company's revenue recognition depends on appropriate classification and documentation of transactions in accordance with GAAP. In general, the Company's power sale transactions, which include PPAs, can be classified in one of four categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Notes 1 and 9 to the financial statements. The Company's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract.
Lease Transactions
The Company considers the following factors to determine whether the sales contract is a lease:
Assessing whether specific property is explicitly or implicitly identified in the agreement;
Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and
Assessing whether the arrangement conveys to the purchaser the right to use the identified property.
If the contract meets the above criteria for a lease, the Company performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of the Company's power sales contracts classified asthat are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and areis included in the Company's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar and wind PPAs are accounted for as contingent revenues and recognized as services are performed.
Non-Derivative and Normal Sale Derivative Transactions
If the power sales contract is not classified as a lease, the Company further considers the following factors to determine proper classification:
Assessing whether the contract meets the definition of a derivative;
Assessing whether the contract meets the definition of a capacity contract;
Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and
Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within the Company's available generating capacity) are accounted for as executory contracts. The related capacity revenue, if any, is recognized on an accrual basis in amounts equal to the lesser of the cumulative levelized amount or the cumulative amount billable under the contract over the respective contract periods. Energy revenuesRevenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. Contracts recorded on the accrual basis represented the majority of the Company's operating revenues.
Cash Flow Hedge Transactions
The Company further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:
Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and
Assessing hedge effectiveness at inception and throughout the contract term.
These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.
Mark-to-Market Transactions
Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Impairment of Long-Lived Assets and Intangibles
The Company's investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company's intangible assets have arisenarise from certain acquisitions and consist of acquired PPAs, thatwhich are amortized to revenue over the term of the respective PPAs and goodwill.PPAs. The Company evaluates the carrying value of these assets in accordance with accounting standards whenever indicators of potential impairment exist, or annually in the case of goodwill.exist. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, and the inability to remarket generating capacity for an extended period. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:
Future demand for electricity based on projections of economic growth and estimates of available generating capacity;
Future power and natural gas prices, which have been quite volatile in recent years; and
Future operating costs.
Acquisition Accounting
The Company acquiresmay acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the operationsdate of acquisition in its consolidated financial statements from the respective date of acquisition.statements. The purchase price, including any contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets acquired and liabilities.liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisitions. acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for successfulpotential or potentialsuccessful acquisitions are expensed as incurred.
Depreciation
BeginningContingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in 2014,service. For contingent consideration with variable payments, the Company changed to component depreciation, wherefair values the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful lives of assets determined by management. Certain generation assets are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. The primary assets in property, plant, and equipment are power plants, which have estimated useful lives ranging from 30 to 45 years. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result inarrangement with any changes that could have a material impact on net incomerecorded in the near term.
When property subject to depreciation is retired or otherwise disposedconsolidated statements of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized.
Prior to 2014, the Company computed depreciation on the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives determined by management.
Investment Tax Credits
Under current tax legislation, certain construction costs related to renewable generating assets are eligible for federal ITCs. A high degree of judgment is required in determining which construction expenditures qualify for federal ITCs.income. See Note 18 to the financial statements under "Income and Other Taxes" for additional fair value information.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers (ASC 606), revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On February 18, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-02, Consolidation (Topic 810):Amendments to the Consolidation Analysis (ASU 2015-02), which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. ASU 2015-02 is effective for fiscal years beginning after December 15, 2015 and is not expected to result in any additional consolidation or deconsolidation of current entities.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note and 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Recently Issued Accounting Standards
Revenue
On April 7, 2015,In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs Leases (Topic 842)( (ASU 2016-02). ASU 2015-03). ASU 2015-032016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015. As permitted,2018 and the Company elected to earlywill adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. new standard effective January 1, 2019.
The new guidance resulted inCompany is currently implementing an adjustment to the presentation of debt issuance costs as an offset toinformation technology system along with the related debt balances primarily in long-term debt totaling $11 million aschanges to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other thanits leases where the reclassification,majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2015-03 did not2016-02 is expected to have ana significant impact on the results of operations, cash flows, or financial condition of the Company. See Note 8 to the financial statementsCompany's balance sheet for disclosures impacted by ASU 2015-03.lessee arrangements.
Other
OnIn November 20, 2015,2016, the FASB issued ASU No. 2015-17,2016-18, Income TaxesStatement of Cash Flows (Topic 740)230): Balance Sheet ClassificationRestricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of Deferred Taxes (cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and2016-18 is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance as of December 31, 20152017, and will be applied its provisions retrospectively to each prior period presented for comparative purposes. Prior topresented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the adoptionFASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2015-17, all deferred income tax assets2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and liabilities were requiredrequires the other components of net periodic pension and postretirement benefit costs to be separated into current and non-current amounts. The new guidance resultedseparately presented in a reclassification from deferredother income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes(expense) in the Company'sincome statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 31, 2014 balance sheet. Other than15, 2017; however, since the reclassification, the adoptionCompany only became a sponsor of ASU 2015-17 did not have an impact on the resultsa qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of operations, cash flows,net periodic benefits costs for 2016 or financial condition of the Company.2017 is required. See Note 52 to the financial statements for disclosures impacted byadditional information.
On August 28, 2017, the FASB issued ASU 2015-17.No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2015.2017. The Company's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with the Company's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet its future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $1.0 billion in 2015, an increase of $400 million compared to 2014. This increase was primarily due to an increase in incomeThe Company also anticipates utilizing third-party tax benefits received and increased revenues from new PPAs, including solar PPAs. Net cash provided from operating activities totaled $603 million in 2014 and $604 million in 2013.
Net cash used for investing activities totaled $2.5 billion, $814 million, and $696 million in 2015, 2014, and 2013, respectively. Net cash used for investing activities in 2015, 2014, and 2013 was primarily due to acquisitions and the construction of renewable facilities.
Net cash provided from financing activities totaled $2.3 billion, $217 million, and $132 million in 2015, 2014, and 2013, respectively. Net cash provided from financing activities in 2015 was primarily due to the issuance of additional senior notes and a 13-month bank loan. Net cash provided from financing activities in 2014 was primarily due to the issuance of commercial paper. Net cash provided from financing activities in 2013 was primarily the resultequity partnerships as one of the issuancefinancing sources to fund its renewable growth strategy where the tax partner will take significantly all of new senior notes.
As of December 31, 2015, the Company had $551 million of unutilized ITCs whichfederal tax benefits. These tax equity partnerships are not expected to be fully utilized until 2020, primarily dueconsolidated in the Company's financial statements using a HLBV methodology to allocate partnership gains and losses to the extension of bonus depreciation.
Significant asset changes in the balance sheet during 2015 included an increase in cash, CWIP, plant in service, and other intangible assets, primarily due to the acquisition and construction of renewable facilities.
Significant liability and stockholder's equity changes in the balance sheet during 2015 included an increase in long-term debt primarily as a result of the issuance of senior notes, an increase in accounts payable related to construction and an increase in noncontrolling interests primarily due to contributions made by class B members for their portion of the related acquisitions.
Sources of Capital
Company. The Company plansrecently secured third-party tax equity funding for the Cactus Flats project subject to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, securities issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
achieving commercial operation and various other customary conditions to closing as well as for the Gaskell West 1 project. The ultimate outcome of these matters cannot be determined at this time.
In addition, the Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in the middle of 2018. Proceeds from the sale may be used for debt redemptions, common stock dividends, working capital, and general corporate purposes as well to support the Company's continuing growth strategy.
Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.As of December 31, 2017, the Company had $2.0 billion of unutilized ITCs and PTCs which are not expected to be fully utilized until 2027. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $339 million in 2016, a decrease of $664 million compared to 2015 primarily due to an increase in unutilized ITCs and PTCs.
Net cash used for investing activities totaled $1.6 billion, $4.8 billion, and $2.5 billion in 2017, 2016, and 2015, respectively, and was primarily due to acquisitions and the construction of renewable and natural gas facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests. Net cash provided from financing activities totaled $2.3 billion in 2015 primarily due to the issuance of additional senior notes and a 13-month term loan.
Significant balance sheet changes include a $1.0 billion increase in plant in service primarily due to new solar and wind facilities being acquired or placed in service, a $284 million increase in deferred income taxes primarily due to additional unutilized PTCs, and a $113 million increase in CWIP primarily due to the construction of a new wind facility and the Mankato natural gas expansion project. In addition, ITC benefits that are deferred and amortized over the asset lives increased $45 million as a result of additional ITCs from new solar facilities being placed in service, offset by ongoing ITC amortization. Other significant changes include a $970 million decrease in cash and cash equivalents and a $456 million decrease in acquisitions payable.
Sources of Capital
The Company plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, and equity contributions from Southern Company. The Company also plans to utilize funds resulting from any potential sale of a 33% equity interest in substantially all of its solar asset portfolio, if completed. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, the Company (excluding its subsidiaries) filesissues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended (1933 Act). The amount of securities registered under the 1933 Act is continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.amended.
As ofAt December 31, 2015,2017, the Company's current liabilities exceeded current assets by $131$474 million due to long-term debt maturing in 2016,the next 12 months, the use of short-term debt as a funding source, and construction payables, as well asfluctuations in cash needs, which can fluctuate significantly due to theboth seasonality of the business and the stage of its acquisitions and construction projects. In 2016,The Company believes the Company expects to utilizeneed for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, the debt capital markets, bank term loans, andthe commercial paper markets as the source of funds for the majority of its maturities.program, and operating cash flows.
The Company obtains financing separately without credit support from any affiliate. To meet liquidity and capital resource requirements, the Company had at December 31, 2015cash and cash equivalents of approximately $830 million.$129 million at December 31, 2017.
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. The Company's subsidiaries are not issuers under the commercial paper program.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of commercial paper were as follows:
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 105 |
| | 2.0% | | $ | 232 |
| | 1.4% | | $ | 628 |
|
December 31, 2016 | $ | — |
| | N/A | | $ | 56 |
| | 0.8% | | $ | 310 |
|
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2017, 2016, and 2015. |
Company FacilityCredit Facilities
At December 31, 2015,2017, the Company (excluding its subsidiaries) had a committed credit facility (Facility) of $600$750 million (Facility).expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In August 2015,May 2017, the Company amended and restated the Facility, which, among other things, extended the maturity date from 20182020 to 20202022 and increased itsthe Company's borrowing ability under this Facility to $600$750 million from $500$600 million. As of December 31, 2015, the total amount availableThe Company's subsidiaries are not borrowers under the Facility was $566 million.
The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Facility, as well as the Company's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company had $113 million of cash collateral posted related to PPA requirements.
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE RoserockGarland Holdings LLC, and RE Garland HoldingsRoserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which arewere non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility providesprovided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that iswas secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being usedcompany, with proceeds directed to finance project costs related to the respective solar facilities currently under construction.facilities. Each Project Credit Facility iswas secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes eachTranquillity, Garland, and Roserock Project Credit Facility asFacilities were fully repaid on October 14, 2016, December 29, 2016, and January 31, 2017, respectively.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of the Company assumed a $217 million construction loan, which was fully repaid in September 2016.
Financing Activities
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Other Debt
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes. At December 31, 2015.2017, this outstanding term loan was included in securities due within one year.
In addition, during 2017, the Company issued a total of $21 million in letters of credit under the Company's credit facilities.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total | | Total Undrawn | | Letter of Credit Facility | | Total Undrawn |
| | | | (in millions) |
Tranquillity | | Earlier of COD or December 31, 2016 | | $ | 86 |
| | $ | 172 |
| | $ | 258 |
| | $ | 147 |
| | $ | 77 |
| | $ | 26 |
|
Roserock | | Earlier of COD or November 30, 2016 | | 63 |
| | 180 |
| | 243 |
| | 243 |
| | 23 |
| | 23 |
|
Garland | | Earlier of COD or November 30, 2016 | | 86 |
| | 308 |
| | 394 |
| | 368 |
| | 49 |
| | 32 |
|
Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 758 |
| | $ | 149 |
| | $ | 81 |
|
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 39 |
|
At BBB- and/or Baa3 | $ | 415 |
|
At BB+ and/or Ba1 (*) | $ | 1,118 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
In addition, the Company has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
While it is unclear how the credit rating agencies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by the Company to mitigate the resulting impacts, which, among other alternatives, could include adjusting the Company's capital structure, the Company's credit ratings could be negatively affected.
Market Price Risk
The Project Credit Facilities had total amounts outstandingCompany is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
At December 31, 20152017, the Company had $945 million of long-term variable rate notes outstanding. If the Company sustained a 100 basis point change in notes payable of $137interest rates for its variable interest rate exposure, the change would effect annualized interest expense by approximately $9 million at December 31, 2017. Since a weighted averagesignificant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.
The Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. The Company has mitigated its exposure to foreign currency exchange rate risk through the use of 2.0%. foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Because energy from the Company's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
For the yearyears ended December 31, 2015, these2017 and 2016, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were as follows: |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Contracts outstanding at the beginning of period, assets (liabilities), net | $ | 16 |
| $ | 1 |
|
Contracts realized or settled | (17 | ) | (3 | ) |
Current period changes (*) | (9 | ) | 18 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | (10 | ) | $ | 16 |
|
| |
(*) | Current period changes also include changes in the fair value of new contracts entered into during the period, if any. |
For the years ending December 31, 2017 and 2016, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows: |
| | | | | | |
| 2017 | 2016 |
Power – net sold | | |
MWH (in millions) | 3.0 |
| 6.1 |
|
Weighted average contract cost per MWH above (below) market prices (in dollars) | $ | (2.67 | ) | $ | 1.45 |
|
Natural Gas – net purchased | | |
Commodity - mmBtu (in millions) | 14.4 |
| 27.1 |
|
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars) | $ | 0.12 |
| $ | (0.27 | ) |
Gains and losses on energy-related derivatives designated as cash flow hedges which are used by the Company to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 8 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2017 all mature in 2018.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit agreements hadratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a maximum amount outstandingmaterial adverse effect on the financial statements as a result of $137 million,counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and an average amount outstanding of $13 million at a weighted average interest rate of 2.0%.Note 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Capital Requirements and Contractual Obligations
The capital program of the Company is subject to periodic review and revision and is currently estimated to total $7.2 billion over the next five years through 2022. This includes approximately $0.9 billion in committed construction, capital improvements, and work to be performed under LTSAs, totaling approximately $400 million for 2018 and an average of approximately $137 million each year from 2019 through 2022. In addition, the capital program includes a further $6.3 billion in planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 11 to the financial statements for additional information.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, other purchase commitments, and pension and other postretirement benefit plans are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 770 |
| | $ | 1,425 |
| | $ | 977 |
| | $ | 2,630 |
| | $ | 5,802 |
|
Interest | 189 |
| | 334 |
| | 278 |
| | 1,524 |
| | 2,325 |
|
Financial derivative obligations(b) | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Operating leases(c) | 22 |
| | 45 |
| | 45 |
| | 815 |
| | 927 |
|
Purchase commitments — | | | | | | | | | |
Capital(d) | 1,099 |
| | 3,661 |
| | 1,750 |
| | — |
| | 6,510 |
|
Fuel(e) | 453 |
| | 555 |
| | 327 |
| | 56 |
| | 1,391 |
|
Purchased power(f) | 40 |
| | 82 |
| | 42 |
| | — |
| | 164 |
|
Other(g) | 149 |
| | 315 |
| | 216 |
| | 1,770 |
| | 2,450 |
|
Pension and other postretirement benefit plans(h) | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Total | $ | 2,735 |
| | $ | 6,418 |
| | $ | 3,635 |
| | $ | 6,795 |
| | $ | 19,583 |
|
| |
(a) | All amounts are reflected based on final maturity dates and include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is a $77 million gain related to the foreign currency hedge of €1.1 billion. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. |
| |
(b) | For additional information, see Notes 1 and 9 to the financial statements. |
| |
(c) | Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. See Note 7 to the financial statements under "Commitments" for additional information. |
| |
(d) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Included in these amounts are planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year, and may vary materially each year due to market opportunities and the Company's ability to execute its growth strategy. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. |
| |
(e) | Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(f) | Purchased power commitments will be resold under a third party agreement at cost. |
| |
(g) | Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission. |
| |
(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company's business, economic conditions, fuel and environmental cost recovery, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, estimated sales and purchases under power sale and purchase agreements, timing of expected future capacity need in existing markets, completion dates of construction projects, projections for the qualified pension plan and postretirement benefit plans contributions, filings with federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
•transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations;
the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the potential sale of a 33% equity interest in substantially all of the Company's solar assets, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Wholesale revenues, non-affiliates | $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
|
Wholesale revenues, affiliates | 392 |
| | 419 |
| | 417 |
|
Other revenues | 12 |
| | 12 |
| | 9 |
|
Total operating revenues | 2,075 |
| | 1,577 |
| | 1,390 |
|
Operating Expenses: | | | | | |
Fuel | 621 |
| | 456 |
| | 441 |
|
Purchased power | 149 |
| | 102 |
| | 93 |
|
Other operations and maintenance | 386 |
| | 354 |
| | 260 |
|
Depreciation and amortization | 503 |
| | 352 |
| | 248 |
|
Taxes other than income taxes | 48 |
| | 23 |
| | 22 |
|
Total operating expenses | 1,707 |
| | 1,287 |
| | 1,064 |
|
Operating Income | 368 |
| | 290 |
| | 326 |
|
Other Income and (Expense): | | | | | |
Interest expense, net of amounts capitalized | (191 | ) | | (117 | ) | | (77 | ) |
Other income (expense), net | 1 |
| | 6 |
| | 1 |
|
Total other income and (expense) | (190 | ) | | (111 | ) | | (76 | ) |
Earnings Before Income Taxes | 178 |
| | 179 |
| | 250 |
|
Income taxes (benefit) | (939 | ) | | (195 | ) | | 21 |
|
Net Income | 1,117 |
| | 374 |
| | 229 |
|
Less: Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Net Income Attributable to the Company | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $39, $(17), and $-, respectively | 63 |
| | (27 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $(46), $36, and $-, respectively | (73 | ) | | 58 |
| | 1 |
|
Total other comprehensive income (loss) | (10 | ) | | 31 |
| | 1 |
|
Less: Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Comprehensive Income Attributable to the Company | $ | 1,061 |
| | $ | 369 |
| | $ | 216 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 536 |
| | 370 |
| | 254 |
|
Deferred income taxes | (263 | ) | | (1,063 | ) | | 42 |
|
Investment tax credits | — |
| | — |
| | 162 |
|
Amortization of investment tax credits | (57 | ) | | (37 | ) | | (19 | ) |
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Accrued income taxes, non-current | 14 |
| | (109 | ) | | 109 |
|
Income taxes receivable, non-current | (61 | ) | | (13 | ) | | — |
|
Other, net | (9 | ) | | 12 |
| | (2 | ) |
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (60 | ) | | (54 | ) | | 18 |
|
-Other current assets | (4 | ) | | (25 | ) | | (30 | ) |
-Accrued taxes | (55 | ) | | 940 |
| | 269 |
|
-Other current liabilities | 1 |
| | 46 |
| | (29 | ) |
Net cash provided from operating activities | 1,155 |
| | 339 |
| | 1,003 |
|
Investing Activities: | | | | | |
Business acquisitions | (1,032 | ) | | (2,294 | ) | | (1,719 | ) |
Property additions | (268 | ) | | (2,114 | ) | | (1,005 | ) |
Change in construction payables | (153 | ) | | (57 | ) | | 251 |
|
Investment in restricted cash | (16 | ) | | (733 | ) | | (159 | ) |
Distribution of restricted cash | 34 |
| | 736 |
| | 154 |
|
Payments pursuant to LTSAs and for equipment not yet received | (203 | ) | | (350 | ) | | (82 | ) |
Other investing activities | 15 |
| | 15 |
| | 22 |
|
Net cash used for investing activities | (1,623 | ) | | (4,797 | ) | | (2,538 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (104 | ) | | 73 |
| | (58 | ) |
Proceeds — | | | | | |
Capital contributions | — |
| | 1,850 |
| | 646 |
|
Senior notes | 525 |
| | 2,831 |
| | 1,650 |
|
Other long-term debt | 43 |
| | 65 |
| | 402 |
|
Redemptions — | | | | | |
Senior notes | (500 | ) | | (200 | ) | | (525 | ) |
Other long-term debt | (18 | ) | | (86 | ) | | (4 | ) |
Distributions to noncontrolling interests | (119 | ) | | (57 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Purchase of membership interests from noncontrolling interests | (59 | ) | | (129 | ) | | — |
|
Payment of common stock dividends | (317 | ) | | (272 | ) | | (131 | ) |
Other financing activities | (33 | ) | | (30 | ) | | (13 | ) |
Net cash provided from (used for) financing activities | (502 | ) | | 4,727 |
| | 2,290 |
|
Net Change in Cash and Cash Equivalents | (970 | ) | | 269 |
| | 755 |
|
Cash and Cash Equivalents at Beginning of Year | 1,099 |
| | 830 |
| | 75 |
|
Cash and Cash Equivalents at End of Year | $ | 129 |
| | $ | 1,099 |
| | $ | 830 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $11, $44, and $14 capitalized, respectively) | $ | 189 |
| | $ | 89 |
| | $ | 74 |
|
Income taxes (net of refunds and investment tax credits) | (487 | ) | | 116 |
| | (518 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 251 |
| | 257 |
|
Accrued acquisitions at year-end | — |
| | 461 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 129 |
| | $ | 1,099 |
|
Receivables — | | | |
Customer accounts receivable | 117 |
| | 102 |
|
Affiliated | 50 |
| | 57 |
|
Other | 98 |
| | 34 |
|
Materials and supplies | 278 |
| | 337 |
|
Prepaid income taxes | 50 |
| | 74 |
|
Other current assets | 36 |
| | 54 |
|
Total current assets | 758 |
| | 1,757 |
|
Property, Plant, and Equipment: | | | |
In service | 13,755 |
| | 12,728 |
|
Less: Accumulated provision for depreciation | 1,910 |
| | 1,484 |
|
Plant in service, net of depreciation | 11,845 |
| | 11,244 |
|
Construction work in progress | 511 |
| | 398 |
|
Total property, plant, and equipment | 12,356 |
| | 11,642 |
|
Other Property and Investments: | | | |
Intangible assets, net of amortization of $47 and $22 at December 31, 2017 and December 31, 2016, respectively | 411 |
| | 436 |
|
Total other property and investments | 411 |
| | 436 |
|
Deferred Charges and Other Assets: | | | |
Prepaid LTSAs | 118 |
| | 101 |
|
Accumulated deferred income taxes | 925 |
| | 594 |
|
Income taxes receivable, non-current | 72 |
| | 11 |
|
Other deferred charges and assets | 566 |
| | 628 |
|
Total deferred charges and other assets | 1,681 |
| | 1,334 |
|
Total Assets | $ | 15,206 |
| | $ | 15,169 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 770 |
| | $ | 560 |
|
Notes payable | 105 |
| | 209 |
|
Accounts payable — | | | |
Affiliated | 102 |
| | 88 |
|
Other | 103 |
| | 278 |
|
Accrued taxes — | | | |
Accrued income taxes | — |
| | 148 |
|
Other accrued taxes | 4 |
| | 7 |
|
Acquisitions payable | 5 |
| | 461 |
|
Other current liabilities | 143 |
| | 152 |
|
Total current liabilities | 1,232 |
| | 1,903 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.50% due 2018 | — |
| | 350 |
|
1.95% due 2019 | 600 |
| | 600 |
|
2.375% due 2020 | 300 |
| | 300 |
|
2.50% due 2021 | 300 |
| | 300 |
|
1.00% due 2022 | 720 |
| | 632 |
|
1.85% to 5.25% due 2023-2046 | 2,664 |
| | 2,592 |
|
Other long-term debt — | | | |
Variable rate (1.88% at 12/31/17) due 2018 | — |
| | 320 |
|
Variable rate (2.18% at 12/31/17) due 2020 | 525 |
| | — |
|
Variable rate (3.75% at 1/1/17) due 2032-2036 | — |
| | 15 |
|
Unamortized debt premium (discount), net | (10 | ) | | (12 | ) |
Unamortized debt issuance expense | (28 | ) | | (29 | ) |
Long-term debt | 5,071 |
| | 5,068 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 199 |
| | 152 |
|
Accumulated deferred ITCs | 1,884 |
| | 1,839 |
|
Other deferred credits and liabilities | 322 |
| | 368 |
|
Total deferred credits and other liabilities | 2,405 |
| | 2,359 |
|
Total Liabilities | 8,708 |
| | 9,330 |
|
Redeemable Noncontrolling Interests | — |
| | 164 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 3,662 |
| | 3,671 |
|
Retained earnings | 1,478 |
| | 724 |
|
Accumulated other comprehensive income | (2 | ) | | 35 |
|
Total common stockholder's equity | 5,138 |
| | 4,430 |
|
Noncontrolling Interests | 1,360 |
| | 1,245 |
|
Total Stockholders' Equity | 6,498 |
| | 5,675 |
|
Total Liabilities and Stockholders' Equity | $ | 15,206 |
| | $ | 15,169 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income | | Total Common Stockholder's Equity | | Noncontrolling Interests(a) | | Total |
| (in millions) |
Balance at December 31, 2014 | — |
| | $ | — |
| | $ | 1,176 |
| | $ | 573 |
| | $ | 3 |
| | $ | 1,752 |
| | $ | 219 |
| | $ | 1,971 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
|
Capital contributions from parent company | — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
Balance at December 31, 2015 | — |
| | — |
| | 1,822 |
| | 657 |
| | 4 |
| | 2,483 |
| | 781 |
| | 3,264 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 338 |
| | — |
| | 338 |
| | — |
| | 338 |
|
Capital contributions from parent company | — |
| | — |
| | 1,850 |
| | — |
| | — |
| | 1,850 |
| | — |
| | 1,850 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 31 |
| | 31 |
| | — |
| | 31 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (272 | ) | | — |
| | (272 | ) | | — |
| | (272 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| | 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Other | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | — |
| | — |
|
Balance at December 31, 2016 | — |
| | — |
| | 3,671 |
| | 724 |
| | 35 |
| | 4,430 |
| | 1,245 |
| | 5,675 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
|
Capital contributions from parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | (10 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (317 | ) | | — |
| | (317 | ) | | — |
| | (317 | ) |
Other comprehensive income transfer from SCS (b) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | (27 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | | (122 | ) |
Net income attributable to noncontrolling interests | �� |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
Other | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | — |
| | $ | — |
| | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
|
| |
(a) | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
(b) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies.
Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis.
The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform to the current year presentation.
The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million, $258 million, and $219 million for the years ended December 31, 2017, 2016, and 2015, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015.
The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million, $193 million, and $146 million for the years ended December 31, 2017, 2016, and 2015, respectively. Of these costs, $192 million, $173 million, and $138 million for the years ended December 31, 2017, 2016, and 2015, respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015.
The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.
Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information.
Revenues
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in wholesale revenues.
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for additional information.
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the Company's top three customers for each of the years presented:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Georgia Power | 11.3 | % | | 16.5 | % | | 15.8 | % |
Duke Energy Corporation | 6.7 | % | | 7.8 | % | | 8.2 | % |
Morgan Stanley Capital Group | 4.5 | % | | N/A |
| | N/A |
|
San Diego Gas & Electric Company | N/A |
| | 5.7 | % | | N/A |
|
Florida Power & Light Company | N/A |
| | N/A |
| | 10.7 | % |
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
Development Costs
The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information.
Property, Plant, and Equipment
The Company's depreciable property, plant, and equipment consists primarily of generation assets.
Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.
When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income.
Depreciation
The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of-
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:
|
| |
Generating facility | Useful life |
Natural gas | Up to 45 years |
Biomass | Up to 40 years |
Solar | Up to 35 years |
Wind | Up to 30 years |
The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.
Asset Retirement Obligations
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability.
Details of the AROs included on the consolidated balance sheets are as follows:
|
| | | | | | | | | |
| 2017 | | | 2016 | |
| (in millions) | |
Balance at beginning of year | $ | 64 |
| | | $ | 21 |
| |
Liabilities incurred | 6 |
| | | 42 |
| |
Accretion | 4 |
| | | 1 |
| |
Cash flow revisions | 4 |
| | | — |
| |
Balance at end of year | $ | 78 |
| | | $ | 64 |
| |
Long-Term Service Agreements
The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated statements of cash flows.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded.
Amortization expense for acquired PPAs was $25 million, $10 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for each of the next five years.
Transmission Receivables/Prepayments
As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
Restricted Cash
The Company has restricted cash primarily related to certain acquisitions and construction projects. The aggregate amount of restricted cash at December 31, 2017 and 2016 was $11 million and $13 million, respectively.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.
Fuel Inventory
Fuel inventory, which is included in other current assets, includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company also maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 9 for additional information regarding derivatives.
The Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 or 2016.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications of amounts included in net income.
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | |
| Qualifying Hedges | Pension and Other Postretirement Benefit Plans | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | 35 |
| $ | — |
| $ | 35 |
|
Current period change | (10 | ) | — |
| (10 | ) |
Other comprehensive income transfer from SCS(*) | — |
| (27 | ) | (27 | ) |
Balance at December 31, 2017 | $ | 25 |
| $ | (27 | ) | $ | (2 | ) |
| |
(*) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of OCI, net of tax of $9 million, was transferred from SCS. |
Variable Interest Entities
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
2. RETIREMENT BENEFITS
Effective in December 2017, 538 employees transferred from SCS to the Company. Accordingly, the Company assumed various compensation and benefit plans including a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). With the transfer of employees, the Company assumed the related benefit obligations from SCS of $139 million for the qualified pension plan (along with trust assets of $138 million) and $11 million for other postretirement benefit plans, together with $36 million in prior service costs and net gains/losses that are in OCI. In 2018, the Company will also begin providing certain defined benefits under a non-qualified pension plan for a select group of management and highly compensated employees. No obligation related to these benefits was assumed in the employee transfer; however, obligations under the non-qualified pension plan for future services rendered by employees will be recognized beginning in 2018 and ultimately funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans that are to be funded on a cash basis.
Prior to the transfer of employees in December 2017, substantially all expenses charged by SCS, including pension and other postretirement benefit costs, were recorded in other operations and maintenance expense. Beginning in 2018, in connection with the adoption of ASU 2017-07, the service cost component of pension and postretirement benefit costs will be recorded in other operations and maintenance expense while the non-service cost components of pension and postretirement benefit costs will be recorded in other income (expense). See Note 1 under "General" for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine the benefit obligations for the pension and other postretirement plans as of the December 31, 2017 measurement date are presented below. |
| | |
Assumptions used to determine benefit obligations: | 2017 |
Pension plans | |
Discount rate | 3.94 | % |
Annual salary increase | 4.46 |
|
Other postretirement benefit plans | |
Discount rate | 3.81 | % |
Annual salary increase | 4.46 |
|
In determining the amount of pension cost to be recognized in 2018, the Company estimates the expected rate of return on pension plan assets using a financial model to project the expected return on the current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on the trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), the trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of the trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) is a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: |
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would have an immaterial effect on the APBO at December 31, 2017.
Pension Plan
The total accumulated benefit obligation for the pension plan was $111 million at December 31, 2017. The projected benefit obligation for the pension plan was $139 million and the fair value of plan assets was $138 million at December 31, 2017.
Presented below are the amounts included in AOCI at December 31, 2017 related to the Company's pension plan that had not yet been recognized in net periodic pension cost, along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 1 |
| | $ | — |
|
Net (gain) loss | 32 |
| | 2 |
|
AOCI | $ | 33 |
| | |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plan. At December 31, 2017, estimated benefit payments average approximately $4 million each year for the next five years, and for the five-year period from 2023 to 2027 estimated benefit payments are $27 million.
Other Postretirement Benefits
The APBO for the other postretirement benefit plan at December 31, 2017 is $11 million. Amounts recognized in the balance sheet at December 31, 2017 related to the Company's other postretirement benefit plan consist of the following: |
| | | |
| 2017 |
| (in millions) |
Employee benefit obligations (included in other deferred credits and liabilities) | $ | (11 | ) |
AOCI | 3 |
|
Presented below are the amounts included in AOCI at December 31, 2017 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018. |
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Net (gain) loss | $ | 3 |
| | $ | — |
|
AOCI | $ | 3 |
| | |
Future benefit payments, which include any prescription drug benefits, and any offset from drug subsidiary receipts, are immaterial for each of the years 2018-2027.
Benefit Plan Assets
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for the pension plan cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan assets as of December 31, 2017, along with the targeted mix of assets for the plan, is presented below:
|
| | | | | |
| Target | | 2017 |
Pension plan assets: | | | |
Domestic equity | 26 | % | | 31 | % |
International equity | 25 |
| | 25 |
|
Fixed income | 23 |
| | 24 |
|
Special situations | 3 |
| | 1 |
|
Real estate investments | 14 |
| | 13 |
|
Private equity | 9 |
| | 6 |
|
Total | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension benefit plan disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan assets as of December 31, 2017. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The fair values of pension plan assets as of December 31, 2017 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 28 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 41 |
|
International equity(*) | 18 |
| | 16 |
| | — |
| | — |
| | 34 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Corporate bonds | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Pooled funds | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 14 |
| | 19 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Total | $ | 53 |
| | $ | 61 |
| | $ | — |
| | $ | 24 |
| | $ | 138 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things,
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
FERC Matters
The Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company is a 65% owner of Plant Stanton A, a natural gas-fired combined-cycle unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission (28%), the Florida Municipal Power Agency (3.5%), and the Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2017, $155 million was recorded in plant in service with associated accumulated depreciation of $55 million. These amounts represent the Company's share of total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the consolidated statements of income.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined, unitary, or consolidated. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current (*) | $ | (566 | ) | | $ | 928 |
| | $ | 12 |
|
Deferred (*) | (312 | ) | | (1,098 | ) | | 10 |
|
| (878 | ) | | (170 | ) | | 22 |
|
State — | | | | | |
Current | (110 | ) | | (60 | ) | | (32 | ) |
Deferred | 49 |
| | 35 |
| | 31 |
|
| (61 | ) | | (25 | ) | | (1 | ) |
Total | $ | (939 | ) | | $ | (195 | ) | | $ | 21 |
|
| |
(*) | ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $316 million for 2017, $1.13 billion for 2016, and $246 million for 2015. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Deferred tax liabilities — | | |
Accelerated depreciation and other property basis differences | $ | 1,922 |
| $ | 2,440 |
|
Levelized capacity revenues | 26 |
| 28 |
|
Other | 6 |
| 27 |
|
Total deferred income tax liabilities | 1,954 |
| 2,495 |
|
Deferred tax assets — | | |
Federal effect of state deferred taxes | 42 |
| 53 |
|
Basis difference on ITCs | 184 |
| 292 |
|
Alternative minimum tax carryforward | 21 |
| 15 |
|
Unrealized tax credits | 2,002 |
| 1,685 |
|
Federal net operating loss (NOL) | 333 |
| 808 |
|
Deferred state tax assets | 77 |
| 60 |
|
Other partnership basis differences | 24 |
| 16 |
|
Other | 10 |
| 8 |
|
Total deferred income tax assets | 2,693 |
| 2,937 |
|
Valuation Allowance | (13 | ) | — |
|
Net deferred income tax assets | 2,680 |
| 2,937 |
|
Total deferred income tax asset (liability) | $ | 726 |
| $ | 442 |
|
| | |
Recognized in the consolidated balance sheets: | | |
Accumulated deferred income taxes – assets | $ | 925 |
| $ | 594 |
|
Accumulated deferred income taxes – liability | $ | (199 | ) | $ | (152 | ) |
Deferred tax liabilities are primarily the result of property-related timing differences, which increased due to bonus depreciation. However, the implementation of the Tax Reform Legislation significantly reduced the amount of accumulated deferred income taxes at December 31, 2017.
Deferred tax assets consist primarily of timing differences related to the carryforward of unrealized federal ITCs, PTCs, net operating loss, and net basis differences on federal ITCs.
Tax Credit Carryforwards
At December 31, 2017, the Company had federal ITC and PTC carryforwards, which are expected to result in $2.0 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2036 but are also expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay the utilization of existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will expire in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The Company had state NOL carryforwards of approximately $1.3 billion at December 31, 2017, which will expire from 2029 to 2035. These carryforwards resulted in deferred tax assets of approximately $61 million as of December 31, 2017. The state NOL carryforwards by state jurisdiction were as follows:
|
| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Expires |
| (in millions) | |
Oklahoma | $ | 978 |
| $ | 46 |
| 2035 |
Florida | 283 |
| 12 |
| 2033 |
South Carolina | 48 |
| 2 |
| 2035 |
Other states | 23 |
| 1 |
| 2029-2035 |
Balance at year end | $ | 1,332 |
| $ | 61 |
| |
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | (22.2 | ) | | (9.1 | ) | | (0.3 | ) |
Amortization of ITC | (31.8 | ) | | (20.6 | ) | | (5.0 | ) |
ITC basis difference | (10.0 | ) | | (89.0 | ) | | (21.5 | ) |
Production tax credits | (72.5 | ) | | (23.3 | ) | | (0.6 | ) |
Tax Reform Legislation | (416.1 | ) | | — |
| | — |
|
Noncontrolling interests | (8.6 | ) | | (6.2 | ) | | (1.7 | ) |
Other | 0.5 |
| | 4.6 |
| | 2.5 |
|
Effective income tax rate (benefit) | (525.7 | )% | | (108.6 | )% | | 8.4 | % |
The Company's effective tax rate decreased in 2017 primarily due to the Tax Reform Legislation. The decrease in 2016 was primarily due to changes in federal ITCs and PTCs.
The Company's deferred federal ITCs are amortized to income tax expense over the life of the respective asset. ITCs amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, the Company received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. While no cash was received related to these incentives in 2017 or 2016, the Company recognized tax credits. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. The tax benefit of PTCs reduced income tax expense by $129 million in 2017, $42 million in 2016 and $1 million in 2015. See "Unrecognized Tax Benefits" herein for further information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Balance at beginning of year | $ | 17 |
| | $ | 8 |
| | $ | 5 |
|
Tax positions increase from current periods | — |
| | 17 |
| | 9 |
|
Tax positions decrease from prior periods | (17 | ) | | (8 | ) | | (6 | ) |
Balance at end of year | $ | — |
| | $ | 17 |
| | $ | 8 |
|
The increase in unrecognized tax benefits from current periods for all years presented, and the decrease from prior periods for all years presented, primarily relate to federal income tax benefits from deferred ITCs and would all impact the Company's effective tax rate, if recognized. The impact on the effective tax rate is determined based on the amount of ITCs which are uncertain.
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Southern Power Company's senior notes, bank term loans, commercial paper, and Facility (as defined herein) are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. The Company's subsidiaries are not issuers, borrowers, or obligors, as applicable, under the senior notes, borrowings from financial institutions, commercial paper, or the Facility. The senior notes, borrowings from financial institutions, commercial paper, and the Facility are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of the Company's subsidiaries. As of December 31, 2017, the Company had no secured debt.
Securities Due Within One Year
At December 31, 2017, the Company had $420 million in term loans and $350 million of senior notes due within one year. At December 31, 2016, the Company had a $60 million term loan, $500 million of senior notes, and $1 million of long-term notes due within one year.
Maturities of long-term debt for the next five years are as follows:
|
| | | |
| December 31, 2017 |
| (in millions) |
2018 | $ | 770 |
|
2019 | 600 |
|
2020 | 825 |
|
2021 | 300 |
|
2022(*) | 677 |
|
| |
(*) | Represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount. |
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the Company had $5.5 billion and $5.3 billion of senior notes outstanding, respectively, which included senior notes due within one year.
Other Long-Term Notes
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
At December 31, 2017, outstanding term loans were included in securities due within one year.
The outstanding term loans as of December 31, 2017 have a covenant that limits debt levels to 65% of total capitalization, as defined in the agreements. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the company to the extent such debt is non-recourse to the company, and capitalization excludes the capital stock or other equity attributable to such subsidiary.
At December 31, 2017, the Company was in compliance with its debt limits.
Bank Credit Arrangements
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under the Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. As of December 31, 2016, $78 million was used for letters of credit and $522 million remained unused. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. The Company's subsidiaries are not parties to the Facility.
The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/4 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017, the Company was in compliance with its debt limits.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. At December 31, 2016, the total amount available under this facility was $82 million. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company has $113 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets in the consolidated balance sheets.
Commercial Paper ProgramAcquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 to the financial statements for additional fair value information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note and 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company only became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 to the financial statements for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with the Company's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet its future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
The Company also anticipates utilizing third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner will take significantly all of the federal tax benefits. These tax equity partnerships are expected to be consolidated in the Company's financial statements using a HLBV methodology to allocate partnership gains and losses to the Company. The Company recently secured third-party tax equity funding for the Cactus Flats project subject to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
achieving commercial operation and various other customary conditions to closing as well as for the Gaskell West 1 project. The ultimate outcome of these matters cannot be determined at this time.
In addition, the Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in the middle of 2018. Proceeds from the sale may be used for debt redemptions, common stock dividends, working capital, and general corporate purposes as well to support the Company's continuing growth strategy.
Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.As of December 31, 2017, the Company had $2.0 billion of unutilized ITCs and PTCs which are not expected to be fully utilized until 2027. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $339 million in 2016, a decrease of $664 million compared to 2015 primarily due to an increase in unutilized ITCs and PTCs.
Net cash used for investing activities totaled $1.6 billion, $4.8 billion, and $2.5 billion in 2017, 2016, and 2015, respectively, and was primarily due to acquisitions and the construction of renewable and natural gas facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests. Net cash provided from financing activities totaled $2.3 billion in 2015 primarily due to the issuance of additional senior notes and a 13-month term loan.
Significant balance sheet changes include a $1.0 billion increase in plant in service primarily due to new solar and wind facilities being acquired or placed in service, a $284 million increase in deferred income taxes primarily due to additional unutilized PTCs, and a $113 million increase in CWIP primarily due to the construction of a new wind facility and the Mankato natural gas expansion project. In addition, ITC benefits that are deferred and amortized over the asset lives increased $45 million as a result of additional ITCs from new solar facilities being placed in service, offset by ongoing ITC amortization. Other significant changes include a $970 million decrease in cash and cash equivalents and a $456 million decrease in acquisitions payable.
Sources of Capital
The Company plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, and equity contributions from Southern Company. The Company also plans to utilize funds resulting from any potential sale of a 33% equity interest in substantially all of its solar asset portfolio, if completed. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, the Company (excluding its subsidiaries) issues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended.
At December 31, 2017, the Company's current liabilities exceeded current assets by $474 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. The Company believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, the debt capital markets, the commercial paper program, and operating cash flows.
The Company obtains financing separately without credit support from any affiliate. To meet liquidity and capital resource requirements, the Company had cash and cash equivalents of approximately $129 million at December 31, 2017.
The Company's commercial paper program (excluding its subsidiaries) is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. CommercialThe Company's subsidiaries are not issuers under the commercial paper was usedprogram.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of short-term borrowings (commercial paper)commercial paper were as follows:
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
December 31, 2014 | $ | 195 |
| | 0.4% | | $ | 54 |
| | 0.4% | | $ | 445 |
|
December 31, 2013 | $ | — |
| | N/A | | $ | 117 |
| | 0.4% | | $ | 271 |
|
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 105 |
| | 2.0% | | $ | 232 |
| | 1.4% | | $ | 628 |
|
December 31, 2016 | $ | — |
| | N/A | | $ | 56 |
| | 0.8% | | $ | 310 |
|
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2015, 2014,2017, 2016, and 2013.2015. |
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under this Facility to $750 million from $600 million. The Company believesCompany's subsidiaries are not borrowers under the needFacility. Proceeds from the Facility may be used for working capital can be adequately met by utilizingand general corporate purposes as well as liquidity support for the Company's commercial paper program,program. Subject to applicable market conditions, the Company expects to renew or replace the Facility, bankas needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Facility, as well as the Company's term loans,loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and operatingcontains a cross-default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company had $113 million of cash flows.collateral posted related to PPA requirements.
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity, Garland, and Roserock Project Credit Facilities were fully repaid on October 14, 2016, December 29, 2016, and January 31, 2017, respectively.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of the Company assumed a $217 million construction loan, which was fully repaid in September 2016.
Financing Activities
Senior Notes
In May 2015,November 2017, the Company issued $350$525 million aggregate principal amount of Series 2015A 1.500%2017A Floating Rate Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020.December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including the Company's growth strategy and continuous construction program, and for a portionredeem all of the repayment at maturity$500
In November 2015, the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company issued $500 million aggregate principal amount of Series 2015C 4.15% Senior Notes due December 1, 2025 and $500 Subsidiary Companies 2017 Annual Report
million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017. The proceeds will be allocated2017 and to funding renewable energy generation projects.repay a portion of the Company's outstanding short-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Other Debt
In August 2015,September 2017, the Company (excludingamended its subsidiaries) entered into a $400$60 million aggregate principal amount 13-month floating rate bankterm loan bearing interest based on one-month LIBOR.to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes, including the Company's growth strategy and continuous construction program.
During 2015, the Company prepaid $4 million of long-term debt to TRE.
Subsidiary Project Credit Facilities
Subsequent topurposes. At December 31, 2015, the Company borrowed $182 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.0%. 2017, this outstanding term loan was included in securities due within one year.
In addition, during 2017, the Company issued $8a total of $21 million in letters of credit.credit under the Company's credit facilities.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
The maximum potential collateral requirements under these contracts at December 31, 20152017 were as follows:
| | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| (in millions) | (in millions) |
At BBB and/or Baa2 | $ | 11 |
| $ | 39 |
|
At BBB- and/or Baa3 | $ | 338 |
| $ | 415 |
|
Below BBB- and/or Baa3 | $ | 1,070 |
| |
At BB+ and/or Ba1 (*) | | $ | 1,118 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that oneAlabama Power or more power pool participantsGeorgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
In addition, the Company has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses if any, resulting from a credit downgrade.
On AugustMarch 24, 2015,2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative followingnegative.
While it is unclear how the announcement ofcredit rating agencies may respond to the proposed merger of a wholly-owned direct subsidiary ofTax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company with and into AGL Resources Inc.its subsidiaries, including the Company, may be negatively impacted. Absent actions by the Company to mitigate the resulting impacts, which, among other alternatives, could include adjusting the Company's capital structure, the Company's credit ratings could be negatively affected.
Market Price Risk
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and interestoccasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
At December 31, 2015,2017, the Company had $13$945 million of long-term variable rate notes outstanding. The effect on annualized interest expense related to variable interest rate exposure ifIf the Company sustained a 100 basis point change in interest rates is immaterial.for its variable interest rate exposure, the change would effect annualized interest expense by approximately $9 million at December 31, 2017. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.
The Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. The Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Because energy from the Company's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
The fair valueFor the years ended December 31, 2017 and 2016, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were immaterial as follows: |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Contracts outstanding at the beginning of period, assets (liabilities), net | $ | 16 |
| $ | 1 |
|
Contracts realized or settled | (17 | ) | (3 | ) |
Current period changes (*) | (9 | ) | 18 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | (10 | ) | $ | 16 |
|
| |
(*) | Current period changes also include changes in the fair value of new contracts entered into during the period, if any. |
For the years ending December 31, 20152017 and 2014.2016, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows: |
| | | | | | |
| 2017 | 2016 |
Power – net sold | | |
MWH (in millions) | 3.0 |
| 6.1 |
|
Weighted average contract cost per MWH above (below) market prices (in dollars) | $ | (2.67 | ) | $ | 1.45 |
|
Natural Gas – net purchased | | |
Commodity - mmBtu (in millions) | 14.4 |
| 27.1 |
|
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars) | $ | 0.12 |
| $ | (0.27 | ) |
Gains and losses on energy-related derivatives designated as cash flow hedges which are used by the Company to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 8 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2015 were immaterial and2017 all mature by 2017.in 2018.
The Company is exposed to losses related to financial instruments in the event of counterparties’counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Company’s Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and Note 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Capital Requirements and Contractual Obligations
The capital program of the Company is currently estimated to total $2.4 billion for 2016, $1.0 billion for 2017, and $1.5 billion for 2018. The construction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitionsrevision and new construction. In addition,is currently estimated to total $7.2 billion over the next five years through 2022. This includes approximately $0.9 billion in committed construction, program includes capital improvements, and work to be performed under LTSAs.LTSAs, totaling approximately $400 million for 2018 and an average of approximately $137 million each year from 2019 through 2022. In addition, the capital program includes a further $6.3 billion in planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statuteslaws and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 211 to the financial statements under "Acquisitions" for additional information.
In addition, TRE can require the Company to purchase its redeemable noncontrolling interests in STR, which owns various solar facilities contracted under long-term PPAs, at fair market value pursuant to the partnership agreement. At December 31, 2015, the redeemable noncontrolling interests was $43 million.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, unrecognized tax benefits,other purchase commitments, and pension and other purchase commitmentspostretirement benefit plans are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
| | | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total | 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) | (in millions) |
Long-term debt(a) — | | | | | | | | | | | | | | | | | | |
Principal | $ | 403 |
| | $ | 850 |
| | $ | 300 |
| | $ | 1,588 |
| | $ | 3,141 |
| $ | 770 |
| | $ | 1,425 |
| | $ | 977 |
| | $ | 2,630 |
| | $ | 5,802 |
|
Interest | 104 |
| | 189 |
| | 169 |
| | 1,280 |
| | 1,742 |
| 189 |
| | 334 |
| | 278 |
| | 1,524 |
| | 2,325 |
|
Financial derivative obligations(b) | 3 |
| | — |
| | — |
| | — |
| | 3 |
| 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Operating leases(c) | 11 |
| | 24 |
| | 25 |
| | 595 |
| | 655 |
| 22 |
| | 45 |
| | 45 |
| | 815 |
| | 927 |
|
Unrecognized tax benefits(d) | 8 |
| | — |
| | — |
| | — |
| | 8 |
| |
Purchase commitments — | | | | | | | | | | | | | | | | | | |
Capital(e) | 2,304 |
| | 2,385 |
| | — |
| | — |
| | 4,689 |
| |
Fuel(f) | 309 |
| | 530 |
| | 432 |
| | 121 |
| | 1,392 |
| |
Purchased power(g) | 38 |
| | 79 |
| | 82 |
| | 42 |
| | 241 |
| |
Other(h) | 107 |
| | 276 |
| | 183 |
| | 785 |
| | 1,351 |
| |
Transmission agreements(i) | 10 |
| | 18 |
| | 16 |
| | 18 |
| | 62 |
| |
Capital(d) | | 1,099 |
| | 3,661 |
| | 1,750 |
| | — |
| | 6,510 |
|
Fuel(e) | | 453 |
| | 555 |
| | 327 |
| | 56 |
| | 1,391 |
|
Purchased power(f) | | 40 |
| | 82 |
| | 42 |
| | — |
| | 164 |
|
Other(g) | | 149 |
| | 315 |
| | 216 |
| | 1,770 |
| | 2,450 |
|
Pension and other postretirement benefit plans(h) | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Total | $ | 3,297 |
| | $ | 4,351 |
| | $ | 1,207 |
| | $ | 4,429 |
| | $ | 13,284 |
| $ | 2,735 |
| | $ | 6,418 |
| | $ | 3,635 |
| | $ | 6,795 |
| | $ | 19,583 |
|
| |
(a) | All amounts are reflected based on final maturity dates.dates and include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is a $77 million gain related to the foreign currency hedge of €1.1 billion. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. |
| |
(b) | For additional information, see Notes 1 and 9 to the financial statements. |
| |
(c) | Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. |
| |
(d) | See Note 57 to the financial statements under "Unrecognized Tax Benefits""Commitments" for additional information. |
| |
(e)(d) | The Company provides estimated capital expenditures for a three-yearfive-year period, including capital expenditures associated with environmental regulations. Included in these amounts are planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year, and may vary materially each year due to market opportunities and the Company's ability to execute its growth strategy. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs.LTSAs which are reflected in "Other." See Note (h)(g) below. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. |
| |
(f)(e) | Primarily includes commitments to purchase, transport, and store natural gas fuel.gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the New York Mercantile Exchange future prices at December 31, 2015.2017. |
| |
(g)(f) | Purchased power commitments will be resold under a third party agreement at cost. |
| |
(h)(g) | Includes LTSA andcommitments related to LTSAs, operation and maintenance agreements.agreements, and transmission. LTSAs include price escalation based on inflation indices. |
| |
(i) | Transmission commitments are based on the Southern Company'sCompany system's current tariff rate for point-to-point transmission. |
| |
(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 20152017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company's business, customer growth, economic recovery,conditions, fuel and environmental cost recovery, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, estimated sales and purchases under power sale and purchase agreements, timing of expected future capacity need in existing markets, completion dates of acquisitions and construction projects, projections for the qualified pension plan and postretirement benefit plans contributions, filings with federal regulatory authorities, impactimpacts of the PATH Act,Tax Reform Legislation, federal and state income tax benefits, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal toregulations governing air, water, land, and land,protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
•transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations;
the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the potential sale of a 33% equity interest in substantially all of the Company's solar assets, which cannot be assured to be completed or beneficial to the Company;
the ongoing partnerships with TRE, First Solar, and Recurrent;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or terrorist incidentsphysical attack and the threat of terrorist incidents;physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Revenues: | | | | | | | | | | |
Wholesale revenues, non-affiliates | $ | 964 |
| | $ | 1,116 |
| | $ | 923 |
| $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
|
Wholesale revenues, affiliates | 417 |
| | 383 |
| | 346 |
| 392 |
| | 419 |
| | 417 |
|
Other revenues | 9 |
| | 2 |
| | 6 |
| 12 |
| | 12 |
| | 9 |
|
Total operating revenues | 1,390 |
| | 1,501 |
| | 1,275 |
| 2,075 |
| | 1,577 |
| | 1,390 |
|
Operating Expenses: | | | | | | | | | | |
Fuel | 441 |
| | 596 |
| | 474 |
| 621 |
| | 456 |
| | 441 |
|
Purchased power, non-affiliates | 72 |
| | 105 |
| | 76 |
| |
Purchased power, affiliates | 21 |
| | 66 |
| | 30 |
| |
Purchased power | | 149 |
| | 102 |
| | 93 |
|
Other operations and maintenance | 260 |
| | 237 |
| | 209 |
| 386 |
| | 354 |
| | 260 |
|
Depreciation and amortization | 248 |
| | 220 |
| | 175 |
| 503 |
| | 352 |
| | 248 |
|
Taxes other than income taxes | 22 |
| | 22 |
| | 21 |
| 48 |
| | 23 |
| | 22 |
|
Total operating expenses | 1,064 |
| | 1,246 |
| | 985 |
| 1,707 |
| | 1,287 |
| | 1,064 |
|
Operating Income | 326 |
| | 255 |
| | 290 |
| 368 |
| | 290 |
| | 326 |
|
Other Income and (Expense): | | | | | | | | | | |
Interest expense, net of amounts capitalized | (77 | ) | | (89 | ) | | (74 | ) | (191 | ) | | (117 | ) | | (77 | ) |
Other income (expense), net | 1 |
| | 6 |
| | (4 | ) | 1 |
| | 6 |
| | 1 |
|
Total other income and (expense) | (76 | ) | | (83 | ) | | (78 | ) | (190 | ) | | (111 | ) | | (76 | ) |
Earnings Before Income Taxes | 250 |
| | 172 |
| | 212 |
| 178 |
| | 179 |
| | 250 |
|
Income taxes (benefit) | 21 |
| | (3 | ) | | 46 |
| (939 | ) | | (195 | ) | | 21 |
|
Net Income | 229 |
| | 175 |
| | 166 |
| 1,117 |
| | 374 |
| | 229 |
|
Less: Net income attributable to noncontrolling interests | 14 |
| | 3 |
| | — |
| 46 |
| | 36 |
| | 14 |
|
Net Income Attributable to the Company | $ | 215 |
| | $ | 172 |
| | $ | 166 |
| $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Net Income | $ | 229 |
| | $ | 175 |
| | $ | 166 |
| $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Other comprehensive income (loss): | | | | | | | | | | |
Qualifying hedges: | | | | | | | | | | |
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, and $2, respectively | 1 |
| | — |
| | 4 |
| |
Total other comprehensive income | 1 |
| | — |
| | 4 |
| |
Changes in fair value, net of tax of $39, $(17), and $-, respectively | | 63 |
| | (27 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $(46), $36, and $-, respectively | | (73 | ) | | 58 |
| | 1 |
|
Total other comprehensive income (loss) | | (10 | ) | | 31 |
| | 1 |
|
Less: Comprehensive income attributable to noncontrolling interests | 14 |
| | 3 |
| | — |
| 46 |
| | 36 |
| | 14 |
|
Comprehensive Income Attributable to the Company | $ | 216 |
| | $ | 172 |
| | $ | 170 |
| $ | 1,061 |
| | $ | 369 |
| | $ | 216 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) | (in millions) |
Operating Activities: | | | | | | | | | | |
Net income | $ | 229 |
| | $ | 175 |
| | $ | 166 |
| $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | | | | | |
Depreciation and amortization | 254 |
| | 225 |
| | 183 |
| |
Depreciation and amortization, total | | 536 |
| | 370 |
| | 254 |
|
Deferred income taxes | 42 |
| | (168 | ) | | 171 |
| (263 | ) | | (1,063 | ) | | 42 |
|
Investment tax credits | 162 |
| | 74 |
| | 158 |
| — |
| | — |
| | 162 |
|
Amortization of investment tax credits | (19 | ) | | (11 | ) | | (6 | ) | (57 | ) | | (37 | ) | | (19 | ) |
Deferred revenues | (15 | ) | | (21 | ) | | (18 | ) | |
Collateral deposits | | (4 | ) | | (102 | ) | | — |
|
Accrued income taxes, non-current | 109 |
| | — |
| | — |
| 14 |
| | (109 | ) | | 109 |
|
Income taxes receivable, non-current | | (61 | ) | | (13 | ) | | — |
|
Other, net | 13 |
| | 11 |
| | 4 |
| (9 | ) | | 12 |
| | (2 | ) |
Changes in certain current assets and liabilities — | | | | | | | | | | |
-Receivables | 18 |
| | (26 | ) | | (11 | ) | (60 | ) | | (54 | ) | | 18 |
|
-Prepaid income taxes | (26 | ) | | 35 |
| | (30 | ) | |
-Other current assets | (4 | ) | | (8 | ) | | (8 | ) | (4 | ) | | (25 | ) | | (30 | ) |
-Accounts payable | (19 | ) | | 30 |
| | (12 | ) | |
-Accrued taxes | 269 |
| | 284 |
| | — |
| (55 | ) | | 940 |
| | 269 |
|
-Other current liabilities | (10 | ) | | 3 |
| | 7 |
| 1 |
| | 46 |
| | (29 | ) |
Net cash provided from operating activities | 1,003 |
| | 603 |
| | 604 |
| 1,155 |
| | 339 |
| | 1,003 |
|
Investing Activities: | | | | | | | | | | |
Plant acquisitions | (1,719 | ) | | (731 | ) | | (132 | ) | |
Business acquisitions | | (1,032 | ) | | (2,294 | ) | | (1,719 | ) |
Property additions | (1,005 | ) | | (21 | ) | | (501 | ) | (268 | ) | | (2,114 | ) | | (1,005 | ) |
Change in construction payables | 251 |
| | — |
| | (4 | ) | (153 | ) | | (57 | ) | | 251 |
|
Investment in restricted cash | (159 | ) | | — |
| | — |
| (16 | ) | | (733 | ) | | (159 | ) |
Distribution of restricted cash | 154 |
| | — |
| | — |
| 34 |
| | 736 |
| | 154 |
|
Payments pursuant to long-term service agreements | (82 | ) | | (61 | ) | | (57 | ) | |
Payments pursuant to LTSAs and for equipment not yet received | | (203 | ) | | (350 | ) | | (82 | ) |
Other investing activities | 22 |
| | (1 | ) | | (2 | ) | 15 |
| | 15 |
| | 22 |
|
Net cash used for investing activities | (2,538 | ) | | (814 | ) | | (696 | ) | (1,623 | ) | | (4,797 | ) | | (2,538 | ) |
Financing Activities: | | | | | | | | | | |
Increase (decrease) in notes payable, net | (58 | ) | | 195 |
| | (71 | ) | (104 | ) | | 73 |
| | (58 | ) |
Proceeds — | | | | | | | | | | |
Capital contributions | 646 |
| | 146 |
| | 1 |
| — |
| | 1,850 |
| | 646 |
|
Senior notes | 1,650 |
| | — |
| | 300 |
| 525 |
| | 2,831 |
| | 1,650 |
|
Other long-term debt | 402 |
| | 10 |
| | 24 |
| 43 |
| | 65 |
| | 402 |
|
Redemptions — | | | | | | | | | | |
Senior notes | (525 | ) | | — |
| | — |
| (500 | ) | | (200 | ) | | (525 | ) |
Other long-term debt | (4 | ) | | (10 | ) | | (9 | ) | (18 | ) | | (86 | ) | | (4 | ) |
Distributions to noncontrolling interests | (18 | ) | | (1 | ) | | (1 | ) | (119 | ) | | (57 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 341 |
| | 8 |
| | 17 |
| 80 |
| | 682 |
| | 341 |
|
Purchase of membership interests from noncontrolling interests | | (59 | ) | | (129 | ) | | — |
|
Payment of common stock dividends | (131 | ) | | (131 | ) | | (129 | ) | (317 | ) | | (272 | ) | | (131 | ) |
Other financing activities | (13 | ) | | — |
| | — |
| (33 | ) | | (30 | ) | | (13 | ) |
Net cash provided from financing activities | 2,290 |
| | 217 |
| | 132 |
| |
Net cash provided from (used for) financing activities | | (502 | ) | | 4,727 |
| | 2,290 |
|
Net Change in Cash and Cash Equivalents | 755 |
| | 6 |
| | 40 |
| (970 | ) | | 269 |
| | 755 |
|
Cash and Cash Equivalents at Beginning of Year | 75 |
| | 69 |
| | 29 |
| 1,099 |
| | 830 |
| | 75 |
|
Cash and Cash Equivalents at End of Year | $ | 830 |
| | $ | 75 |
| | $ | 69 |
| $ | 129 |
| | $ | 1,099 |
| | $ | 830 |
|
Supplemental Cash Flow Information: | | | | | | | | | | |
Cash paid (received) during the period for — | | | | | | | | | | |
Interest (net of $14, $-, and $9 capitalized, respectively) | $ | 74 |
| | $ | 85 |
| | $ | 60 |
| |
Interest (net of $11, $44, and $14 capitalized, respectively) | | $ | 189 |
| | $ | 89 |
| | $ | 74 |
|
Income taxes (net of refunds and investment tax credits) | (518 | ) | | (220 | ) | | (226 | ) | (487 | ) | | 116 |
| | (518 | ) |
Noncash transactions — | | | �� | | | | | | | |
Accrued property additions at year-end | 257 |
| | 1 |
| | 6 |
| 32 |
| | 251 |
| | 257 |
|
Acquisitions | — |
| | 229 |
| | — |
| |
Capital contributions from noncontrolling interests | — |
| | 221 |
| | — |
| |
Accrued acquisitions at year-end | | — |
| | 461 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 20152017 and 20142016
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | Assets | 2015 |
| | 2014 |
| 2017 |
| | 2016 |
|
| (in millions) | (in millions) |
Current Assets: | | | | | | |
Cash and cash equivalents | $ | 830 |
| | $ | 75 |
| $ | 129 |
| | $ | 1,099 |
|
Receivables — | | | | | | |
Customer accounts receivable | 75 |
| | 77 |
| 117 |
| | 102 |
|
Other accounts receivable | 19 |
| | 15 |
| |
Affiliated companies | 30 |
| | 34 |
| |
Fossil fuel stock, at average cost | 16 |
| | 22 |
| |
Materials and supplies, at average cost | 63 |
| | 58 |
| |
Affiliated | | 50 |
| | 57 |
|
Other | | 98 |
| | 34 |
|
Materials and supplies | | 278 |
| | 337 |
|
Prepaid income taxes | 45 |
| | 19 |
| 50 |
| | 74 |
|
Other prepaid expenses | 23 |
| | 17 |
| |
Assets from risk management activities | 7 |
| | 5 |
| |
Other current assets | | 36 |
| | 54 |
|
Total current assets | 1,108 |
| | 322 |
| 758 |
| | 1,757 |
|
Property, Plant, and Equipment: | | | | | | |
In service | 7,275 |
| | 5,657 |
| 13,755 |
| | 12,728 |
|
Less accumulated provision for depreciation | 1,248 |
| | 1,035 |
| |
Less: Accumulated provision for depreciation | | 1,910 |
| | 1,484 |
|
Plant in service, net of depreciation | 6,027 |
| | 4,622 |
| 11,845 |
| | 11,244 |
|
Construction work in progress | 1,137 |
| | 11 |
| 511 |
| | 398 |
|
Total property, plant, and equipment | 7,164 |
| | 4,633 |
| 12,356 |
| | 11,642 |
|
Other Property and Investments: | | | | | | |
Goodwill | 2 |
| | 2 |
| |
Other intangible assets, net of amortization of $12 and $9 at December 31, 2015 and December 31, 2014, respectively | 317 |
| | 47 |
| |
Intangible assets, net of amortization of $47 and $22 at December 31, 2017 and December 31, 2016, respectively | | 411 |
| | 436 |
|
Total other property and investments | 319 |
| | 49 |
| 411 |
| | 436 |
|
Deferred Charges and Other Assets: | | | | | | |
Prepaid long-term service agreements | 166 |
| | 124 |
| |
Other deferred charges and assets — affiliated | 9 |
| | 5 |
| |
Other deferred charges and assets — non-affiliated | 139 |
| | 100 |
| |
Prepaid LTSAs | | 118 |
| | 101 |
|
Accumulated deferred income taxes | | 925 |
| | 594 |
|
Income taxes receivable, non-current | | 72 |
| | 11 |
|
Other deferred charges and assets | | 566 |
| | 628 |
|
Total deferred charges and other assets | 314 |
| | 229 |
| 1,681 |
| | 1,334 |
|
Total Assets | $ | 8,905 |
| | $ | 5,233 |
| $ | 15,206 |
| | $ | 15,169 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 20152017 and 20142016
Southern Power Company and Subsidiary Companies 20152017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 770 |
| | $ | 560 |
|
Notes payable | 105 |
| | 209 |
|
Accounts payable — | | | |
Affiliated | 102 |
| | 88 |
|
Other | 103 |
| | 278 |
|
Accrued taxes — | | | |
Accrued income taxes | — |
| | 148 |
|
Other accrued taxes | 4 |
| | 7 |
|
Acquisitions payable | 5 |
| | 461 |
|
Other current liabilities | 143 |
| | 152 |
|
Total current liabilities | 1,232 |
| | 1,903 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.50% due 2018 | — |
| | 350 |
|
1.95% due 2019 | 600 |
| | 600 |
|
2.375% due 2020 | 300 |
| | 300 |
|
2.50% due 2021 | 300 |
| | 300 |
|
1.00% due 2022 | 720 |
| | 632 |
|
1.85% to 5.25% due 2023-2046 | 2,664 |
| | 2,592 |
|
Other long-term debt — | | | |
Variable rate (1.88% at 12/31/17) due 2018 | — |
| | 320 |
|
Variable rate (2.18% at 12/31/17) due 2020 | 525 |
| | — |
|
Variable rate (3.75% at 1/1/17) due 2032-2036 | — |
| | 15 |
|
Unamortized debt premium (discount), net | (10 | ) | | (12 | ) |
Unamortized debt issuance expense | (28 | ) | | (29 | ) |
Long-term debt | 5,071 |
| | 5,068 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 199 |
| | 152 |
|
Accumulated deferred ITCs | 1,884 |
| | 1,839 |
|
Other deferred credits and liabilities | 322 |
| | 368 |
|
Total deferred credits and other liabilities | 2,405 |
| | 2,359 |
|
Total Liabilities | 8,708 |
| | 9,330 |
|
Redeemable Noncontrolling Interests | — |
| | 164 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 3,662 |
| | 3,671 |
|
Retained earnings | 1,478 |
| | 724 |
|
Accumulated other comprehensive income | (2 | ) | | 35 |
|
Total common stockholder's equity | 5,138 |
| | 4,430 |
|
Noncontrolling Interests | 1,360 |
| | 1,245 |
|
Total Stockholders' Equity | 6,498 |
| | 5,675 |
|
Total Liabilities and Stockholders' Equity | $ | 15,206 |
| | $ | 15,169 |
|
Commitments and Contingent Matters (See notes) |
| |
|
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2015 |
| | 2014 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 403 |
| | $ | 525 |
|
Notes payable | 137 |
| | 195 |
|
Accounts payable — | | | |
Affiliated | 66 |
| | 78 |
|
Other | 327 |
| | 30 |
|
Accrued taxes — | | | |
Accrued income taxes | 198 |
| | 70 |
|
Other accrued taxes | 5 |
| | 3 |
|
Accrued interest | 23 |
| | 30 |
|
Contingent consideration | 36 |
| | 8 |
|
Other current liabilities | 44 |
| | 6 |
|
Total current liabilities | 1,239 |
| | 945 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.85% due 2017 | 500 |
| | — |
|
1.50% due 2018 | 350 |
| | — |
|
2.375% due 2020 | 300 |
| | — |
|
4.15% to 6.375% due 2025-2043 | 1,575 |
| | 1,075 |
|
Other long-term notes — variable rate (3.50% at 1/1/16) due 2032-2035 | 13 |
| | 19 |
|
Unamortized debt premium (discount), net | — |
| | 2 |
|
Unamortized debt issuance expense | (19 | ) | | (11 | ) |
Long-term debt | 2,719 |
| | 1,085 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 601 |
| | 559 |
|
Accumulated deferred investment tax credits | 889 |
| | 601 |
|
Accrued income taxes, non-current | 109 |
| | — |
|
Asset retirement obligations | 21 |
| | 13 |
|
Deferred capacity revenues — affiliated | 17 |
| | 15 |
|
Other deferred credits and liabilities | 3 |
| | 5 |
|
Total deferred credits and other liabilities | 1,640 |
| | 1,193 |
|
Total Liabilities | 5,598 |
| | 3,223 |
|
Redeemable Noncontrolling Interests | 43 |
| | 39 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 1,822 |
| | 1,176 |
|
Retained earnings | 657 |
| | 573 |
|
Accumulated other comprehensive income | 4 |
| | 3 |
|
Total common stockholder's equity | 2,483 |
| | 1,752 |
|
Noncontrolling Interests | 781 |
| | 219 |
|
Total Stockholders' Equity | 3,264 |
| | 1,971 |
|
Total Liabilities and Stockholders' Equity | $ | 8,905 |
| | $ | 5,233 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 20152017, 20142016, and 20132015
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder's Equity | | Noncontrolling Interests | | Total | Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income | | Total Common Stockholder's Equity | | Noncontrolling Interests(a) | | Total |
| (in millions) | (in millions) |
Balance at December 31, 2012 | — |
| | $ | — |
| | $ | 1,028 |
| | $ | 495 |
| | $ | (1 | ) | | $ | 1,522 |
| | $ | — |
| | $ | 1,522 |
| |
Net income attributable to the Company | — |
| | — |
| | — |
| | 166 |
| | — |
| | 166 |
| | — |
| | 166 |
| |
Capital contributions from parent company | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
| | — |
| | 4 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (129 | ) | | — |
| | (129 | ) | | — |
| | (129 | ) | |
Balance at December 31, 2013 | — |
| | — |
| | 1,029 |
| | 532 |
| | 3 |
| | 1,564 |
| | — |
| | 1,564 |
| |
Net income attributable to the Company | — |
| | — |
| | — |
| | 172 |
| | — |
| | 172 |
| | — |
| | 172 |
| |
Capital contributions from parent company | — |
| | — |
| | 147 |
| | — |
| | — |
| | 147 |
| | — |
| | 147 |
| |
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) | |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 221 |
| | 221 |
| |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (2 | ) | |
Balance at December 31, 2014 | — |
| | — |
| | 1,176 |
| | 573 |
| | 3 |
| | 1,752 |
| | 219 |
| | 1,971 |
| — |
| | $ | — |
| | $ | 1,176 |
| | $ | 573 |
| | $ | 3 |
| | $ | 1,752 |
| | $ | 219 |
| | $ | 1,971 |
|
Net income attributable to the Company | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
| |
Net income attributable to Southern Power | | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
|
Capital contributions from parent company | — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
| — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Net loss attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
Balance at December 31, 2015 | | — |
| | — |
| | 1,822 |
| | 657 |
| | 4 |
| | 2,483 |
| | 781 |
| | 3,264 |
|
Net income attributable to Southern Power | | — |
| | — |
| | — |
| | 338 |
| | — |
| | 338 |
| | — |
| | 338 |
|
Capital contributions from parent company | | — |
| | — |
| | 1,850 |
| | — |
| | — |
| | 1,850 |
| | — |
| | 1,850 |
|
Other comprehensive income | | — |
| | — |
| | — |
| | — |
| | 31 |
| | 31 |
| | — |
| | 31 |
|
Cash dividends on common stock | | — |
| | — |
| | — |
| | (272 | ) | | — |
| | (272 | ) | | — |
| | (272 | ) |
Capital contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| | 618 |
|
Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | | (57 | ) |
Purchase of membership interests from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Balance at December 31, 2015 | — |
| | $ | — |
| | $ | 1,822 |
| | $ | 657 |
| | $ | 4 |
| | $ | 2,483 |
| | $ | 781 |
| | $ | 3,264 |
| |
Other | | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | — |
| | — |
|
Balance at December 31, 2016 | | — |
| | — |
| | 3,671 |
| | 724 |
| | 35 |
| | 4,430 |
| | 1,245 |
| | 5,675 |
|
Net income attributable to Southern Power | | — |
| | — |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
|
Capital contributions from parent company | | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Other comprehensive income | | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | (10 | ) |
Cash dividends on common stock | | — |
| | — |
| | — |
| | (317 | ) | | — |
| | (317 | ) | | — |
| | (317 | ) |
Other comprehensive income transfer from SCS (b) | | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | (27 | ) |
Capital contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | 79 |
|
Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | | (122 | ) |
Net income attributable to noncontrolling interests | | �� |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | 44 |
|
Reclassification from redeemable noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
Other | | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | | — |
| | $ | — |
| | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
|
| |
(a) | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
(b) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, SouthernLINC Wireless, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services
Effective in December 2017, 538 employees transferred from SCS to the publicCompany. The Company became obligated for related employee costs including pension, other postretirement benefits, and provides fiber cablestock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services withinrendered at amounts in compliance with FERC regulations. The Company adopted the Southeast.same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis.
Southern Power Company and certain of its generation subsidiaries are subject to regulation by the FERC. The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform to the current year presentation.
The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation.
Recently Issued Accounting Standards
Revenue
The Financial Accounting Standards Board's (FASB)In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), revises replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for fiscal yearsreporting periods beginning after December 15, 2017. The Company continuesapplied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to evaluateapply the requirementsstandard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606. The ultimate impact of the new standard has606 did not yet been determined.result in a cumulative adjustment.
Leases
OnIn February 18, 2015,2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-02,2016-02, ConsolidationLeases (Topic 810):842)Amendments (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the Consolidation Analysis (balance sheet a lease liability and a right-of-use asset for all leases. ASU 2015-02), which makes certain2016-02 also changes to both the variable interest modelrecognition, measurement, and the voting model, including changes topresentation of expense associated with leases and provides clarification regarding the identification of variable interests, the variable interest entity characteristics forcertain components of contracts that would represent a limited partnership or similar entity, and the primary beneficiary determination.lease. The accounting required by lessors is relatively unchanged. ASU 2015-022016-02 is effective for fiscal years beginning after December 15, 20152018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation
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Southern Power Company and Subsidiary Companies 2017 Annual Report
facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in any additional consolidation or deconsolidation of current entities.have a significant impact on the Company's balance sheet for lessee arrangements.
Other
On April 7, 2015,In November 2016, the FASB issued ASU No. 2015-03,2016-18, Interest – ImputationStatement of Interest (Subtopic 835-30)Cash Flows (Topic 230): SimplifyingRestricted Cash (ASU 2016-18). ASU 2016-18 eliminates the Presentation of Debt Issuance Costs (ASU 2015-03). ASU 2015-03 requires that debt issuance costs relatedneed to a recognized debt liability be presentedreflect transfers between cash and restricted cash in operating, investing, and financing activities in the balance sheetstatement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as a direct deduction from the carrying amount of that debt liability andrestricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2015. As permitted, the Company elected to early adopt the guidance as of December 31, 20152017, and will be applied its provisions retrospectively to each prior period presented for comparative purposes.presented. The new guidance resulted in an adjustment to the presentation of debt issuance costs as an offset to the related debt balances primarily in long-term debt totaling $11 million as of December 31, 2014. These debt issuance costs were previously presented within other deferred charges and assets. Other than the reclassification, the adoption ofCompany adopted ASU 2015-03 did not have an2016-18 effective January 1, 2018 with no material impact on the results of operations, cash flows, orits financial condition of the Company. See Note 8 for disclosures impacted by ASU 2015-03.statements.
On November 20, 2015,March 10, 2017, the FASB issued ASU No. 2015-17,2017-07, Income TaxesCompensation - Retirement Benefits (Topic 740)715): Balance Sheet ClassificationImproving the Presentation of Deferred Taxes Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost( (ASU 2017-07). ASU 2015-17),2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which simplifiesis effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of deferred income taxes.net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information.
On August 28, 2017, the FASB issued ASU 2015-17 requires deferred tax assetsNo. 2017-12, Derivatives and liabilitiesHedging (Topic 815): Targeted Improvements to be presented as non-current in a classified balance sheetAccounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the2018, with early adoption permitted. The Company elected to early adopt the guidance as of December 31, 2015 and applied its provisions retrospectively to each prior period presented for comparative purposes. Prior to the adoption ofadopted ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The new guidance resulted in a reclassification from deferred income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. Other than the reclassification, the adoption of ASU 2015-17 did not have an2017-12 effective January 1, 2018 with no material impact on the results of operations, cash flows, orits financial condition of the Company. See Note 5 for disclosures impacted by ASU 2015-17.statements.
Affiliate Transactions
Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million, $258 million, and $219 million for the years ended December 31, 2017, 2016, and 2015, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015.
The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions
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Southern Power Company and Subsidiary Companies 2015 Annual Report
associated with the Southern Company system's fleet of generating units. BecausePrior to December 2017, the Company has nodid not have employees and thus all employee-related charges arewere rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS amounted to approximatelytotaled $218 million, $193 million, and $146 million infor the years ended December 31, 2017, 2016, and 2015, $126 million in 2014, and $118 million in 2013.respectively. Of these costs, approximately$192 million, $173 million, and $138 million infor the years ended December 31, 2017, 2016, and 2015, $125 million in 2014, and $114 million in 2013respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015.
The Company also has several agreements with SCS for transmission services. Transmission services purchased from affiliatesSCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in 2015, $7 million in 2014, and $8 million in 2013.the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.
Total revenuesPrior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from all PPAs with affiliates,Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to
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Southern Power Company and Subsidiary Companies 2017 Annual Report
Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in wholesale revenue affiliatesfuel expense on the consolidated statements of income,income.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $219$25 million $153for the year ended December 31, 2017 and $7 million and $150 millionfor the period subsequent to Southern Company Gas' investment in 2015, 2014, and 2013, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $109 million, $75 million, and $69 million in 2015, 2014, and 2013, respectively.SNG through December 31, 2016.
The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information.
The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information.
Revenues
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in wholesale revenues.
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for additional information.
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information.
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Southern Power Company and Subsidiary Companies 2017 Annual Report
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the Company's top three customers for each of the years presented:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Georgia Power | 11.3 | % | | 16.5 | % | | 15.8 | % |
Duke Energy Corporation | 6.7 | % | | 7.8 | % | | 8.2 | % |
Morgan Stanley Capital Group | 4.5 | % | | N/A |
| | N/A |
|
San Diego Gas & Electric Company | N/A |
| | 5.7 | % | | N/A |
|
Florida Power & Light Company | N/A |
| | N/A |
| | 10.7 | % |
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
Development Costs
The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information.
Property, Plant, and Equipment
The Company's depreciable property, plant, and equipment consists primarily of generation assets.
Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.
When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income.
Depreciation
The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of-
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:
|
| |
Generating facility | Useful life |
Natural gas | Up to 45 years |
Biomass | Up to 40 years |
Solar | Up to 35 years |
Wind | Up to 30 years |
The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.
Asset Retirement Obligations
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability.
Details of the AROs included on the consolidated balance sheets are as follows:
|
| | | | | | | | | |
| 2017 | | | 2016 | |
| (in millions) | |
Balance at beginning of year | $ | 64 |
| | | $ | 21 |
| |
Liabilities incurred | 6 |
| | | 42 |
| |
Accretion | 4 |
| | | 1 |
| |
Cash flow revisions | 4 |
| | | — |
| |
Balance at end of year | $ | 78 |
| | | $ | 64 |
| |
Long-Term Service Agreements
The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated statements of cash flows.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded.
Amortization expense for acquired PPAs was $25 million, $10 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for each of the next five years.
Transmission Receivables/Prepayments
As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
Restricted Cash
The Company has restricted cash primarily related to certain acquisitions and construction projects. The aggregate amount of restricted cash at December 31, 2017 and 2016 was $11 million and $13 million, respectively.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.
Fuel Inventory
Fuel inventory, which is included in other current assets, includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company also maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 9 for additional information regarding derivatives.
The Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 or 2016.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications of amounts included in net income.
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | |
| Qualifying Hedges | Pension and Other Postretirement Benefit Plans | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | 35 |
| $ | — |
| $ | 35 |
|
Current period change | (10 | ) | — |
| (10 | ) |
Other comprehensive income transfer from SCS(*) | — |
| (27 | ) | (27 | ) |
Balance at December 31, 2017 | $ | 25 |
| $ | (27 | ) | $ | (2 | ) |
| |
(*) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of OCI, net of tax of $9 million, was transferred from SCS. |
Variable Interest Entities
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
2. RETIREMENT BENEFITS
Effective in December 2017, 538 employees transferred from SCS to the Company. Accordingly, the Company assumed various compensation and benefit plans including a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). With the transfer of employees, the Company assumed the related benefit obligations from SCS of $139 million for the qualified pension plan (along with trust assets of $138 million) and $11 million for other postretirement benefit plans, together with $36 million in prior service costs and net gains/losses that are in OCI. In 2018, the Company will also begin providing certain defined benefits under a non-qualified pension plan for a select group of management and highly compensated employees. No obligation related to these benefits was assumed in the employee transfer; however, obligations under the non-qualified pension plan for future services rendered by employees will be recognized beginning in 2018 and ultimately funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans that are to be funded on a cash basis.
Prior to the transfer of employees in December 2017, substantially all expenses charged by SCS, including pension and other postretirement benefit costs, were recorded in other operations and maintenance expense. Beginning in 2018, in connection with the adoption of ASU 2017-07, the service cost component of pension and postretirement benefit costs will be recorded in other operations and maintenance expense while the non-service cost components of pension and postretirement benefit costs will be recorded in other income (expense). See Note 1 under "General" for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine the benefit obligations for the pension and other postretirement plans as of the December 31, 2017 measurement date are presented below. |
| | |
Assumptions used to determine benefit obligations: | 2017 |
Pension plans | |
Discount rate | 3.94 | % |
Annual salary increase | 4.46 |
|
Other postretirement benefit plans | |
Discount rate | 3.81 | % |
Annual salary increase | 4.46 |
|
In determining the amount of pension cost to be recognized in 2018, the Company estimates the expected rate of return on pension plan assets using a financial model to project the expected return on the current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on the trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), the trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of the trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) is a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: |
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would have an immaterial effect on the APBO at December 31, 2017.
Pension Plan
The total accumulated benefit obligation for the pension plan was $111 million at December 31, 2017. The projected benefit obligation for the pension plan was $139 million and the fair value of plan assets was $138 million at December 31, 2017.
Presented below are the amounts included in AOCI at December 31, 2017 related to the Company's pension plan that had not yet been recognized in net periodic pension cost, along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 1 |
| | $ | — |
|
Net (gain) loss | 32 |
| | 2 |
|
AOCI | $ | 33 |
| | |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plan. At December 31, 2017, estimated benefit payments average approximately $4 million each year for the next five years, and for the five-year period from 2023 to 2027 estimated benefit payments are $27 million.
Other Postretirement Benefits
The APBO for the other postretirement benefit plan at December 31, 2017 is $11 million. Amounts recognized in the balance sheet at December 31, 2017 related to the Company's other postretirement benefit plan consist of the following: |
| | | |
| 2017 |
| (in millions) |
Employee benefit obligations (included in other deferred credits and liabilities) | $ | (11 | ) |
AOCI | 3 |
|
Presented below are the amounts included in AOCI at December 31, 2017 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018. |
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Net (gain) loss | $ | 3 |
| | $ | — |
|
AOCI | $ | 3 |
| | |
Future benefit payments, which include any prescription drug benefits, and any offset from drug subsidiary receipts, are immaterial for each of the years 2018-2027.
Benefit Plan Assets
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for the pension plan cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan assets as of December 31, 2017, along with the targeted mix of assets for the plan, is presented below:
|
| | | | | |
| Target | | 2017 |
Pension plan assets: | | | |
Domestic equity | 26 | % | | 31 | % |
International equity | 25 |
| | 25 |
|
Fixed income | 23 |
| | 24 |
|
Special situations | 3 |
| | 1 |
|
Real estate investments | 14 |
| | 13 |
|
Private equity | 9 |
| | 6 |
|
Total | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension benefit plan disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan assets as of December 31, 2017. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The fair values of pension plan assets as of December 31, 2017 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 28 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 41 |
|
International equity(*) | 18 |
| | 16 |
| | — |
| | — |
| | 34 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Corporate bonds | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Pooled funds | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 14 |
| | 19 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Total | $ | 53 |
| | $ | 61 |
| | $ | — |
| | $ | 24 |
| | $ | 138 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things,
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
FERC Matters
The Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company is a 65% owner of Plant Stanton A, a natural gas-fired combined-cycle unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission (28%), the Florida Municipal Power Agency (3.5%), and the Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2017, $155 million was recorded in plant in service with associated accumulated depreciation of $55 million. These amounts represent the Company's share of total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the consolidated statements of income.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined, unitary, or consolidated. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Federal — | | | | | |
Current (*) | $ | (566 | ) | | $ | 928 |
| | $ | 12 |
|
Deferred (*) | (312 | ) | | (1,098 | ) | | 10 |
|
| (878 | ) | | (170 | ) | | 22 |
|
State — | | | | | |
Current | (110 | ) | | (60 | ) | | (32 | ) |
Deferred | 49 |
| | 35 |
| | 31 |
|
| (61 | ) | | (25 | ) | | (1 | ) |
Total | $ | (939 | ) | | $ | (195 | ) | | $ | 21 |
|
| |
(*) | ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in federal income tax expense above. ITCs and PTCs reclassified in this manner include $316 million for 2017, $1.13 billion for 2016, and $246 million for 2015. These ITCs and PTCs are included in the following table of temporary differences as unrealized tax credits. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Deferred tax liabilities — | | |
Accelerated depreciation and other property basis differences | $ | 1,922 |
| $ | 2,440 |
|
Levelized capacity revenues | 26 |
| 28 |
|
Other | 6 |
| 27 |
|
Total deferred income tax liabilities | 1,954 |
| 2,495 |
|
Deferred tax assets — | | |
Federal effect of state deferred taxes | 42 |
| 53 |
|
Basis difference on ITCs | 184 |
| 292 |
|
Alternative minimum tax carryforward | 21 |
| 15 |
|
Unrealized tax credits | 2,002 |
| 1,685 |
|
Federal net operating loss (NOL) | 333 |
| 808 |
|
Deferred state tax assets | 77 |
| 60 |
|
Other partnership basis differences | 24 |
| 16 |
|
Other | 10 |
| 8 |
|
Total deferred income tax assets | 2,693 |
| 2,937 |
|
Valuation Allowance | (13 | ) | — |
|
Net deferred income tax assets | 2,680 |
| 2,937 |
|
Total deferred income tax asset (liability) | $ | 726 |
| $ | 442 |
|
| | |
Recognized in the consolidated balance sheets: | | |
Accumulated deferred income taxes – assets | $ | 925 |
| $ | 594 |
|
Accumulated deferred income taxes – liability | $ | (199 | ) | $ | (152 | ) |
Deferred tax liabilities are primarily the result of property-related timing differences, which increased due to bonus depreciation. However, the implementation of the Tax Reform Legislation significantly reduced the amount of accumulated deferred income taxes at December 31, 2017.
Deferred tax assets consist primarily of timing differences related to the carryforward of unrealized federal ITCs, PTCs, net operating loss, and net basis differences on federal ITCs.
Tax Credit Carryforwards
At December 31, 2017, the Company had federal ITC and PTC carryforwards, which are expected to result in $2.0 billion of federal income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2027. The PTC carryforwards begin expiring in 2036 but are also expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay the utilization of existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had a consolidated federal NOL carryforward of approximately $2.3 billion at December 31, 2017. The federal NOL will expire in 2037 but is expected to be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The Company had state NOL carryforwards of approximately $1.3 billion at December 31, 2017, which will expire from 2029 to 2035. These carryforwards resulted in deferred tax assets of approximately $61 million as of December 31, 2017. The state NOL carryforwards by state jurisdiction were as follows:
|
| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Expires |
| (in millions) | |
Oklahoma | $ | 978 |
| $ | 46 |
| 2035 |
Florida | 283 |
| 12 |
| 2033 |
South Carolina | 48 |
| 2 |
| 2035 |
Other states | 23 |
| 1 |
| 2029-2035 |
Balance at year end | $ | 1,332 |
| $ | 61 |
| |
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | (22.2 | ) | | (9.1 | ) | | (0.3 | ) |
Amortization of ITC | (31.8 | ) | | (20.6 | ) | | (5.0 | ) |
ITC basis difference | (10.0 | ) | | (89.0 | ) | | (21.5 | ) |
Production tax credits | (72.5 | ) | | (23.3 | ) | | (0.6 | ) |
Tax Reform Legislation | (416.1 | ) | | — |
| | — |
|
Noncontrolling interests | (8.6 | ) | | (6.2 | ) | | (1.7 | ) |
Other | 0.5 |
| | 4.6 |
| | 2.5 |
|
Effective income tax rate (benefit) | (525.7 | )% | | (108.6 | )% | | 8.4 | % |
The Company's effective tax rate decreased in 2017 primarily due to the Tax Reform Legislation. The decrease in 2016 was primarily due to changes in federal ITCs and PTCs.
The Company's deferred federal ITCs are amortized to income tax expense over the life of the respective asset. ITCs amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, the Company received cash related to federal ITCs under the renewable energy incentives of $162 million for the year ended December 31, 2015. While no cash was received related to these incentives in 2017 or 2016, the Company recognized tax credits. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015. The tax benefit of PTCs reduced income tax expense by $129 million in 2017, $42 million in 2016 and $1 million in 2015. See "Unrecognized Tax Benefits" herein for further information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $55 million related to certain changes in state apportionment rates and net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Balance at beginning of year | $ | 17 |
| | $ | 8 |
| | $ | 5 |
|
Tax positions increase from current periods | — |
| | 17 |
| | 9 |
|
Tax positions decrease from prior periods | (17 | ) | | (8 | ) | | (6 | ) |
Balance at end of year | $ | — |
| | $ | 17 |
| | $ | 8 |
|
The increase in unrecognized tax benefits from current periods for all years presented, and the decrease from prior periods for all years presented, primarily relate to federal income tax benefits from deferred ITCs and would all impact the Company's effective tax rate, if recognized. The impact on the effective tax rate is determined based on the amount of ITCs which are uncertain.
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Southern Power Company's senior notes, bank term loans, commercial paper, and Facility (as defined herein) are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. The Company's subsidiaries are not issuers, borrowers, or obligors, as applicable, under the senior notes, borrowings from financial institutions, commercial paper, or the Facility. The senior notes, borrowings from financial institutions, commercial paper, and the Facility are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of the Company's subsidiaries. As of December 31, 2017, the Company had no secured debt.
Securities Due Within One Year
At December 31, 2017, the Company had $420 million in term loans and $350 million of senior notes due within one year. At December 31, 2016, the Company had a $60 million term loan, $500 million of senior notes, and $1 million of long-term notes due within one year.
Maturities of long-term debt for the next five years are as follows:
|
| | | |
| December 31, 2017 |
| (in millions) |
2018 | $ | 770 |
|
2019 | 600 |
|
2020 | 825 |
|
2021 | 300 |
|
2022(*) | 677 |
|
| |
(*) | Represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount. |
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the Company had $5.5 billion and $5.3 billion of senior notes outstanding, respectively, which included senior notes due within one year.
Other Long-Term Notes
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.
At December 31, 2017, outstanding term loans were included in securities due within one year.
The outstanding term loans as of December 31, 2017 have a covenant that limits debt levels to 65% of total capitalization, as defined in the agreements. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the company to the extent such debt is non-recourse to the company, and capitalization excludes the capital stock or other equity attributable to such subsidiary.
At December 31, 2017, the Company was in compliance with its debt limits.
Bank Credit Arrangements
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under the Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. As of December 31, 2016, $78 million was used for letters of credit and $522 million remained unused. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. The Company's subsidiaries are not parties to the Facility.
The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/4 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2017, the Company was in compliance with its debt limits.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. At December 31, 2016, the total amount available under this facility was $82 million. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company has $113 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets in the consolidated balance sheets.
Acquisition Accounting
The Company acquiresmay acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the operationsdate of acquisition in its consolidated financial statements from the respective date of acquisition.statements. The purchase price, including any contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets acquired and liabilities.liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisitions. acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for successfulpotential or potentialsuccessful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 to the financial statements for additional fair value information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note and 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company only became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 to the financial statements for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with the Company's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet its future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
The Company also anticipates utilizing third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner will take significantly all of the federal tax benefits. These tax equity partnerships are expected to be consolidated in the Company's financial statements using a HLBV methodology to allocate partnership gains and losses to the Company. The Company recently secured third-party tax equity funding for the Cactus Flats project subject to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
achieving commercial operation and various other customary conditions to closing as well as for the Gaskell West 1 project. The ultimate outcome of these matters cannot be determined at this time.
In addition, the Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in the middle of 2018. Proceeds from the sale may be used for debt redemptions, common stock dividends, working capital, and general corporate purposes as well to support the Company's continuing growth strategy.
Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.As of December 31, 2017, the Company had $2.0 billion of unutilized ITCs and PTCs which are not expected to be fully utilized until 2027. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $339 million in 2016, a decrease of $664 million compared to 2015 primarily due to an increase in unutilized ITCs and PTCs.
Net cash used for investing activities totaled $1.6 billion, $4.8 billion, and $2.5 billion in 2017, 2016, and 2015, respectively, and was primarily due to acquisitions and the construction of renewable and natural gas facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests. Net cash provided from financing activities totaled $2.3 billion in 2015 primarily due to the issuance of additional senior notes and a 13-month term loan.
Significant balance sheet changes include a $1.0 billion increase in plant in service primarily due to new solar and wind facilities being acquired or placed in service, a $284 million increase in deferred income taxes primarily due to additional unutilized PTCs, and a $113 million increase in CWIP primarily due to the construction of a new wind facility and the Mankato natural gas expansion project. In addition, ITC benefits that are deferred and amortized over the asset lives increased $45 million as a result of additional ITCs from new solar facilities being placed in service, offset by ongoing ITC amortization. Other significant changes include a $970 million decrease in cash and cash equivalents and a $456 million decrease in acquisitions payable.
Sources of Capital
The Company plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, and equity contributions from Southern Company. The Company also plans to utilize funds resulting from any potential sale of a 33% equity interest in substantially all of its solar asset portfolio, if completed. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, the Company (excluding its subsidiaries) issues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended.
At December 31, 2017, the Company's current liabilities exceeded current assets by $474 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. The Company believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, the debt capital markets, the commercial paper program, and operating cash flows.
The Company obtains financing separately without credit support from any affiliate. To meet liquidity and capital resource requirements, the Company had cash and cash equivalents of approximately $129 million at December 31, 2017.
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. The Company's subsidiaries are not issuers under the commercial paper program.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of commercial paper were as follows:
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 105 |
| | 2.0% | | $ | 232 |
| | 1.4% | | $ | 628 |
|
December 31, 2016 | $ | — |
| | N/A | | $ | 56 |
| | 0.8% | | $ | 310 |
|
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2017, 2016, and 2015. |
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under this Facility to $750 million from $600 million. The Company's subsidiaries are not borrowers under the Facility. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Facility, as well as the Company's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company had $113 million of cash collateral posted related to PPA requirements.
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity, Garland, and Roserock Project Credit Facilities were fully repaid on October 14, 2016, December 29, 2016, and January 31, 2017, respectively.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of the Company assumed a $217 million construction loan, which was fully repaid in September 2016.
Financing Activities
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Other Debt
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes. At December 31, 2017, this outstanding term loan was included in securities due within one year.
In addition, during 2017, the Company issued a total of $21 million in letters of credit under the Company's credit facilities.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 39 |
|
At BBB- and/or Baa3 | $ | 415 |
|
At BB+ and/or Ba1 (*) | $ | 1,118 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
In addition, the Company has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
While it is unclear how the credit rating agencies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by the Company to mitigate the resulting impacts, which, among other alternatives, could include adjusting the Company's capital structure, the Company's credit ratings could be negatively affected.
Market Price Risk
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
At December 31, 2017, the Company had $945 million of long-term variable rate notes outstanding. If the Company sustained a 100 basis point change in interest rates for its variable interest rate exposure, the change would effect annualized interest expense by approximately $9 million at December 31, 2017. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.
The Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. The Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Because energy from the Company's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
For the years ended December 31, 2017 and 2016, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were as follows: |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Contracts outstanding at the beginning of period, assets (liabilities), net | $ | 16 |
| $ | 1 |
|
Contracts realized or settled | (17 | ) | (3 | ) |
Current period changes (*) | (9 | ) | 18 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | (10 | ) | $ | 16 |
|
| |
(*) | Current period changes also include changes in the fair value of new contracts entered into during the period, if any. |
For the years ending December 31, 2017 and 2016, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows: |
| | | | | | |
| 2017 | 2016 |
Power – net sold | | |
MWH (in millions) | 3.0 |
| 6.1 |
|
Weighted average contract cost per MWH above (below) market prices (in dollars) | $ | (2.67 | ) | $ | 1.45 |
|
Natural Gas – net purchased | | |
Commodity - mmBtu (in millions) | 14.4 |
| 27.1 |
|
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars) | $ | 0.12 |
| $ | (0.27 | ) |
Gains and losses on energy-related derivatives designated as cash flow hedges which are used by the Company to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 8 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2017 all mature in 2018.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and Note 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Capital Requirements and Contractual Obligations
The capital program of the Company is subject to periodic review and revision and is currently estimated to total $7.2 billion over the next five years through 2022. This includes approximately $0.9 billion in committed construction, capital improvements, and work to be performed under LTSAs, totaling approximately $400 million for 2018 and an average of approximately $137 million each year from 2019 through 2022. In addition, the capital program includes a further $6.3 billion in planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 11 to the financial statements for additional information.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, other purchase commitments, and pension and other postretirement benefit plans are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 770 |
| | $ | 1,425 |
| | $ | 977 |
| | $ | 2,630 |
| | $ | 5,802 |
|
Interest | 189 |
| | 334 |
| | 278 |
| | 1,524 |
| | 2,325 |
|
Financial derivative obligations(b) | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Operating leases(c) | 22 |
| | 45 |
| | 45 |
| | 815 |
| | 927 |
|
Purchase commitments — | | | | | | | | | |
Capital(d) | 1,099 |
| | 3,661 |
| | 1,750 |
| | — |
| | 6,510 |
|
Fuel(e) | 453 |
| | 555 |
| | 327 |
| | 56 |
| | 1,391 |
|
Purchased power(f) | 40 |
| | 82 |
| | 42 |
| | — |
| | 164 |
|
Other(g) | 149 |
| | 315 |
| | 216 |
| | 1,770 |
| | 2,450 |
|
Pension and other postretirement benefit plans(h) | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Total | $ | 2,735 |
| | $ | 6,418 |
| | $ | 3,635 |
| | $ | 6,795 |
| | $ | 19,583 |
|
| |
(a) | All amounts are reflected based on final maturity dates and include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is a $77 million gain related to the foreign currency hedge of €1.1 billion. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. |
| |
(b) | For additional information, see Notes 1 and 9 to the financial statements. |
| |
(c) | Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. See Note 7 to the financial statements under "Commitments" for additional information. |
| |
(d) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Included in these amounts are planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year, and may vary materially each year due to market opportunities and the Company's ability to execute its growth strategy. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. |
| |
(e) | Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(f) | Purchased power commitments will be resold under a third party agreement at cost. |
| |
(g) | Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission. |
| |
(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company's business, economic conditions, fuel and environmental cost recovery, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, estimated sales and purchases under power sale and purchase agreements, timing of expected future capacity need in existing markets, completion dates of construction projects, projections for the qualified pension plan and postretirement benefit plans contributions, filings with federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
•transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations;
the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the potential sale of a 33% equity interest in substantially all of the Company's solar assets, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Wholesale revenues, non-affiliates | $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
|
Wholesale revenues, affiliates | 392 |
| | 419 |
| | 417 |
|
Other revenues | 12 |
| | 12 |
| | 9 |
|
Total operating revenues | 2,075 |
| | 1,577 |
| | 1,390 |
|
Operating Expenses: | | | | | |
Fuel | 621 |
| | 456 |
| | 441 |
|
Purchased power | 149 |
| | 102 |
| | 93 |
|
Other operations and maintenance | 386 |
| | 354 |
| | 260 |
|
Depreciation and amortization | 503 |
| | 352 |
| | 248 |
|
Taxes other than income taxes | 48 |
| | 23 |
| | 22 |
|
Total operating expenses | 1,707 |
| | 1,287 |
| | 1,064 |
|
Operating Income | 368 |
| | 290 |
| | 326 |
|
Other Income and (Expense): | | | | | |
Interest expense, net of amounts capitalized | (191 | ) | | (117 | ) | | (77 | ) |
Other income (expense), net | 1 |
| | 6 |
| | 1 |
|
Total other income and (expense) | (190 | ) | | (111 | ) | | (76 | ) |
Earnings Before Income Taxes | 178 |
| | 179 |
| | 250 |
|
Income taxes (benefit) | (939 | ) | | (195 | ) | | 21 |
|
Net Income | 1,117 |
| | 374 |
| | 229 |
|
Less: Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Net Income Attributable to the Company | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $39, $(17), and $-, respectively | 63 |
| | (27 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $(46), $36, and $-, respectively | (73 | ) | | 58 |
| | 1 |
|
Total other comprehensive income (loss) | (10 | ) | | 31 |
| | 1 |
|
Less: Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Comprehensive Income Attributable to the Company | $ | 1,061 |
| | $ | 369 |
| | $ | 216 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 536 |
| | 370 |
| | 254 |
|
Deferred income taxes | (263 | ) | | (1,063 | ) | | 42 |
|
Investment tax credits | — |
| | — |
| | 162 |
|
Amortization of investment tax credits | (57 | ) | | (37 | ) | | (19 | ) |
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Accrued income taxes, non-current | 14 |
| | (109 | ) | | 109 |
|
Income taxes receivable, non-current | (61 | ) | | (13 | ) | | — |
|
Other, net | (9 | ) | | 12 |
| | (2 | ) |
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (60 | ) | | (54 | ) | | 18 |
|
-Other current assets | (4 | ) | | (25 | ) | | (30 | ) |
-Accrued taxes | (55 | ) | | 940 |
| | 269 |
|
-Other current liabilities | 1 |
| | 46 |
| | (29 | ) |
Net cash provided from operating activities | 1,155 |
| | 339 |
| | 1,003 |
|
Investing Activities: | | | | | |
Business acquisitions | (1,032 | ) | | (2,294 | ) | | (1,719 | ) |
Property additions | (268 | ) | | (2,114 | ) | | (1,005 | ) |
Change in construction payables | (153 | ) | | (57 | ) | | 251 |
|
Investment in restricted cash | (16 | ) | | (733 | ) | | (159 | ) |
Distribution of restricted cash | 34 |
| | 736 |
| | 154 |
|
Payments pursuant to LTSAs and for equipment not yet received | (203 | ) | | (350 | ) | | (82 | ) |
Other investing activities | 15 |
| | 15 |
| | 22 |
|
Net cash used for investing activities | (1,623 | ) | | (4,797 | ) | | (2,538 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (104 | ) | | 73 |
| | (58 | ) |
Proceeds — | | | | | |
Capital contributions | — |
| | 1,850 |
| | 646 |
|
Senior notes | 525 |
| | 2,831 |
| | 1,650 |
|
Other long-term debt | 43 |
| | 65 |
| | 402 |
|
Redemptions — | | | | | |
Senior notes | (500 | ) | | (200 | ) | | (525 | ) |
Other long-term debt | (18 | ) | | (86 | ) | | (4 | ) |
Distributions to noncontrolling interests | (119 | ) | | (57 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Purchase of membership interests from noncontrolling interests | (59 | ) | | (129 | ) | | — |
|
Payment of common stock dividends | (317 | ) | | (272 | ) | | (131 | ) |
Other financing activities | (33 | ) | | (30 | ) | | (13 | ) |
Net cash provided from (used for) financing activities | (502 | ) | | 4,727 |
| | 2,290 |
|
Net Change in Cash and Cash Equivalents | (970 | ) | | 269 |
| | 755 |
|
Cash and Cash Equivalents at Beginning of Year | 1,099 |
| | 830 |
| | 75 |
|
Cash and Cash Equivalents at End of Year | $ | 129 |
| | $ | 1,099 |
| | $ | 830 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $11, $44, and $14 capitalized, respectively) | $ | 189 |
| | $ | 89 |
| | $ | 74 |
|
Income taxes (net of refunds and investment tax credits) | (487 | ) | | 116 |
| | (518 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 251 |
| | 257 |
|
Accrued acquisitions at year-end | — |
| | 461 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 129 |
| | $ | 1,099 |
|
Receivables — | | | |
Customer accounts receivable | 117 |
| | 102 |
|
Affiliated | 50 |
| | 57 |
|
Other | 98 |
| | 34 |
|
Materials and supplies | 278 |
| | 337 |
|
Prepaid income taxes | 50 |
| | 74 |
|
Other current assets | 36 |
| | 54 |
|
Total current assets | 758 |
| | 1,757 |
|
Property, Plant, and Equipment: | | | |
In service | 13,755 |
| | 12,728 |
|
Less: Accumulated provision for depreciation | 1,910 |
| | 1,484 |
|
Plant in service, net of depreciation | 11,845 |
| | 11,244 |
|
Construction work in progress | 511 |
| | 398 |
|
Total property, plant, and equipment | 12,356 |
| | 11,642 |
|
Other Property and Investments: | | | |
Intangible assets, net of amortization of $47 and $22 at December 31, 2017 and December 31, 2016, respectively | 411 |
| | 436 |
|
Total other property and investments | 411 |
| | 436 |
|
Deferred Charges and Other Assets: | | | |
Prepaid LTSAs | 118 |
| | 101 |
|
Accumulated deferred income taxes | 925 |
| | 594 |
|
Income taxes receivable, non-current | 72 |
| | 11 |
|
Other deferred charges and assets | 566 |
| | 628 |
|
Total deferred charges and other assets | 1,681 |
| | 1,334 |
|
Total Assets | $ | 15,206 |
| | $ | 15,169 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 770 |
| | $ | 560 |
|
Notes payable | 105 |
| | 209 |
|
Accounts payable — | | | |
Affiliated | 102 |
| | 88 |
|
Other | 103 |
| | 278 |
|
Accrued taxes — | | | |
Accrued income taxes | — |
| | 148 |
|
Other accrued taxes | 4 |
| | 7 |
|
Acquisitions payable | 5 |
| | 461 |
|
Other current liabilities | 143 |
| | 152 |
|
Total current liabilities | 1,232 |
| | 1,903 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.50% due 2018 | — |
| | 350 |
|
1.95% due 2019 | 600 |
| | 600 |
|
2.375% due 2020 | 300 |
| | 300 |
|
2.50% due 2021 | 300 |
| | 300 |
|
1.00% due 2022 | 720 |
| | 632 |
|
1.85% to 5.25% due 2023-2046 | 2,664 |
| | 2,592 |
|
Other long-term debt — | | | |
Variable rate (1.88% at 12/31/17) due 2018 | — |
| | 320 |
|
Variable rate (2.18% at 12/31/17) due 2020 | 525 |
| | — |
|
Variable rate (3.75% at 1/1/17) due 2032-2036 | — |
| | 15 |
|
Unamortized debt premium (discount), net | (10 | ) | | (12 | ) |
Unamortized debt issuance expense | (28 | ) | | (29 | ) |
Long-term debt | 5,071 |
| | 5,068 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 199 |
| | 152 |
|
Accumulated deferred ITCs | 1,884 |
| | 1,839 |
|
Other deferred credits and liabilities | 322 |
| | 368 |
|
Total deferred credits and other liabilities | 2,405 |
| | 2,359 |
|
Total Liabilities | 8,708 |
| | 9,330 |
|
Redeemable Noncontrolling Interests | — |
| | 164 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 3,662 |
| | 3,671 |
|
Retained earnings | 1,478 |
| | 724 |
|
Accumulated other comprehensive income | (2 | ) | | 35 |
|
Total common stockholder's equity | 5,138 |
| | 4,430 |
|
Noncontrolling Interests | 1,360 |
| | 1,245 |
|
Total Stockholders' Equity | 6,498 |
| | 5,675 |
|
Total Liabilities and Stockholders' Equity | $ | 15,206 |
| | $ | 15,169 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income | | Total Common Stockholder's Equity | | Noncontrolling Interests(a) | | Total |
| (in millions) |
Balance at December 31, 2014 | — |
| | $ | — |
| | $ | 1,176 |
| | $ | 573 |
| | $ | 3 |
| | $ | 1,752 |
| | $ | 219 |
| | $ | 1,971 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
|
Capital contributions from parent company | — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
Balance at December 31, 2015 | — |
| | — |
| | 1,822 |
| | 657 |
| | 4 |
| | 2,483 |
| | 781 |
| | 3,264 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 338 |
| | — |
| | 338 |
| | — |
| | 338 |
|
Capital contributions from parent company | — |
| | — |
| | 1,850 |
| | — |
| | — |
| | 1,850 |
| | — |
| | 1,850 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 31 |
| | 31 |
| | — |
| | 31 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (272 | ) | | — |
| | (272 | ) | | — |
| | (272 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| | 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Other | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | — |
| | — |
|
Balance at December 31, 2016 | — |
| | — |
| | 3,671 |
| | 724 |
| | 35 |
| | 4,430 |
| | 1,245 |
| | 5,675 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
|
Capital contributions from parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | (10 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (317 | ) | | — |
| | (317 | ) | | — |
| | (317 | ) |
Other comprehensive income transfer from SCS (b) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | (27 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | | (122 | ) |
Net income attributable to noncontrolling interests | �� |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
Other | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | — |
| | $ | — |
| | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
|
| |
(a) | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
(b) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies.
Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis.
The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform to the current year presentation.
The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million, $258 million, and $219 million for the years ended December 31, 2017, 2016, and 2015, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015.
The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million, $193 million, and $146 million for the years ended December 31, 2017, 2016, and 2015, respectively. Of these costs, $192 million, $173 million, and $138 million for the years ended December 31, 2017, 2016, and 2015, respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015.
The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.
Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information.
Revenues
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in operatingwholesale revenues.
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for additional information.
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the Company's top three customers:customers for each of the years presented:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Georgia Power | 15.8 | % | | 10.1 | % | | 11.8 | % | 11.3 | % | | 16.5 | % | | 15.8 | % |
FPL | 10.7 | % | | 9.7 | % | | 10.7 | % | |
Duke Energy Corporation | 8.2 | % | | 9.1 | % | | 10.3 | % | 6.7 | % | | 7.8 | % | | 8.2 | % |
Morgan Stanley Capital Group | | 4.5 | % | | N/A |
| | N/A |
|
San Diego Gas & Electric Company | | N/A |
| | 5.7 | % | | N/A |
|
Florida Power & Light Company | | N/A |
| | N/A |
| | 10.7 | % |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
Development Costs
The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The creditsCompany applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and are amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the creditsITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal production tax credits (PTC),PTCs, which are recorded toas an income tax expensebenefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during the year2017 and will be carried forward and utilized in future years. The ITC carryforwards begin expiring in 2034, but are expected to be fully utilized by 2020. See Note 5 under "Effective Tax Rate" for additional information.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
The Company's depreciable property, plant, and equipment consists primarily of generation assets.
Property, plant, and equipment is stated at original cost.cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.
When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income.
Depreciation
Beginning in 2014, theThe Company changed toapplies component depreciation, where the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful liveslife of assets as determined by management.the asset. Certain generation assets related to natural gas-fired facilities are now depreciated on a units-of-productionunits-of-
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
The primary assets in property, plant, and equipment are power plants,generating facilities, which generally have estimated useful lives ranging from 30 to 45 years. as follows:
|
| |
Generating facility | Useful life |
Natural gas | Up to 45 years |
Biomass | Up to 40 years |
Solar | Up to 35 years |
Wind | Up to 30 years |
The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. Plant in service as of December 31, 2015 and 2014 that is depreciated on a units-of-production basis was approximately $485 million and $470 million, respectively.
When property subject to depreciation is retired or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized.
Prior to 2014, the Company computed depreciation of the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives as determined by management.
Asset Retirement Obligations
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life.
In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability for AROs primarily relates to the Company's solar and wind facilities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Details of the AROs included inon the consolidated balance sheets are as follows:
| | | 2015 | | 2014 | | 2017 | | 2016 | |
| (in millions) | | (in millions) | |
Balance at beginning of year | $ | 13 |
| | $ | 4 |
| | $ | 64 |
| | $ | 21 |
| |
Liabilities incurred | 7 |
| | 8 |
| | 6 |
| | 42 |
| |
Accretion | 1 |
| | 1 |
| | 4 |
| | 1 |
| |
Cash flow revisions | | 4 |
| | — |
| |
Balance at end of year | $ | 21 |
| | $ | 13 |
| | $ | 78 |
| | $ | 64 |
| |
Long-Term Service Agreements
The Company has entered into LTSAs for the purpose of securing maintenance support for substantially all of its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. AllAt the time work is performed, which typically occurs during planned inspections, an appropriate amount is capitalizedtransferred from the prepayment to property, plant, and equipment or charged to expenseexpense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as appropriate based on the naturea noncash transaction for purposes of the work when performed; therefore, these charges are non-cash and are not reflected in theconsolidated statements of cash flows.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, PPAs thatwhich are amortized over the term of the PPA and goodwill resulting from acquisitions. ThePPAs, which have a weighted average term of these PPAs is 2019 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
The amortizationAmortization expense for the acquired PPAs was $25 million, $10 million, and $3 million for each of the years ended December 31, 2017, 2016, and 2015, 2014, and 2013 was $3 million,respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for future periods is as follows:
|
| | | |
| Amortization Expense |
| (in millions) |
2016 | $ | 10 |
|
2017 | 17 |
|
2018 | 17 |
|
2019 | 17 |
|
2020 | 17 |
|
2021 and beyond | 239 |
|
Total | $ | 317 |
|
each of the next five years.Transmission Receivables/Prepayments
As parta result of the Company's growth throughfrom the acquisition and construction of renewablegenerating facilities, the Company has transmission receivables and/or prepayments representing the reimbursable portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Emission Reduction Credits
The Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the EPA as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost and were $11 million at each of December 31, 2015 and 2014. The cost of emission reduction offsets to be surrendered are generally transferred to CWIP upon commencement of the related construction.
Restricted CashConstruction Projects
Construction Projects Completed and in Progress
During 2017, in accordance with its overall growth strategy, the Company completed construction of and placed in service, or continued construction of, the projects set forth in the table below.
|
| | | | | | | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual / Expected COD | PPA Counterparties | PPA Contract Period |
Construction Projects Completed During the Year Ended December 31, 2017 |
East Pecos | Solar | 120 | | Pecos County, TX | 100 | % | | March 2017 | Austin Energy | 15 years |
Lamesa | Solar | 102 | | Dawson County, TX | 100 | % | | April 2017 | City of Garland, Texas | 15 years |
Projects Under Construction at December 31, 2017 |
Cactus Flats | Wind | 148 | | Concho County, TX | 100 | % | (*) | Third quarter 2018 | General Motors and General Mills | 12 years and 15 years |
Mankato Expansion | Natural Gas | 345 | | Mankato, MN | 100% |
| | Second quarter 2019 | Northern States Power Company | 20 years |
(*) On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests.
Total aggregate construction costs for projects under construction at December 31, 2017, excluding acquisition costs and including construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, total costs of construction incurred for these projects was $188 million, all of which remained in CWIP.
Development Projects
During 2017, as part of the Company's renewable development strategy, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
During 2016, the Company entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
The useCompany is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of funds received underbusiness. The Company's business activities are subject to extensive governmental regulation related to public health and the credit facilitiesenvironment, such as regulation of RE Tranquillity LLC,air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and RE Garland Holdings LLCwas subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Roserock facility for the same amount. The amounts withheld are restrictedincluded in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction purposes.contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The aggregate amount outstandingCompany intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Revenue Recognition
The Company's revenue recognition depends on appropriate classification and documentation of transactions in accordance with GAAP. In general, the Company's power sale transactions, which include PPAs, can be classified in one of four categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Notes 1 and 9 to the financial statements. The Company's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of December 31, 2015 was $5 millioneach contract.
Lease Transactions
The Company considers the following factors to determine whether the sales contract is a lease:
Assessing whether specific property is explicitly or implicitly identified in the agreement;
Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and
Assessing whether the arrangement conveys to the purchaser the right to use the identified property.
If the contract meets the above criteria for a lease, the Company performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of the Company's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in the Company's operating revenues. Energy revenues and other deferred chargescontingent revenues are recognized in the period the energy is delivered or the service is rendered.
Non-Derivative and assets — non-affiliated.Normal Sale Derivative Transactions
If the power sales contract is not classified as a lease, the Company further considers the following factors to determine proper classification:
Assessing whether the contract meets the definition of a derivative;
Assessing whether the contract meets the definition of a capacity contract;
Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and
Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within the Company's available generating capacity) are accounted for as executory contracts. The related capacity revenue, if any, is recognized on an accrual basis in amounts equal to the lesser of the cumulative levelized amount or the cumulative amount billable under the contract over the respective contract periods. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Fuel Inventory
Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.
Financial InstrumentsFlow Hedge Transactions
The Company usesfurther considers the following in designating other derivative financial instruments to limit exposure to fluctuations in interest rates,contracts for the pricessale of certain fuel purchases,electricity as cash flow hedges of anticipated sale transactions:
Identifying the hedging instrument, the forecasted hedged transaction, and electricity purchasesthe nature of the risk being hedged; and sales. All derivative financial instruments
Assessing hedge effectiveness at inception and throughout the contract term.
These contracts are recognized as either assets or liabilitiesaccounted for on the balance sheets (included in "Other" or shown separately as "Risk Management Activities")a fair value basis and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially allrecorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.
Mark-to-Market Transactions
Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues.
Impairment of Long-Lived Assets and Intangibles
The Company's bulk energy purchasesinvestments in long-lived assets are primarily generation assets, whether in service or under construction. The Company's intangible assets arise from certain acquisitions and sales contractsconsist of acquired PPAs, which are amortized to revenue over the term of the respective PPAs. The Company evaluates the carrying value of these assets whenever indicators of potential impairment exist. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, and the inability to remarket generating capacity for an extended period. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:
Future demand for electricity based on projections of economic growth and estimates of available generating capacity;
Future power and natural gas prices, which have been quite volatile in recent years; and
Future operating costs.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a derivative are excludedbusiness, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value accounting requirements because they qualify forof the "normal" scope exception,identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for underas an asset acquisition.
The purchase price of each asset acquisition is allocated based on the accrual method. Derivativerelative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, that qualifydiscount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as cash flow hedges of anticipated transactions resultincurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the deferralconsolidated statements of related gains and losses in AOCI untilincome. See Note 8 to the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify asfinancial statements for additional fair value hedgesinformation.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are marked to market through current periodsupported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statement line itemstatements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note and 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where they will eventually settle.the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash flows from derivatives are classified onFlows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flowsflows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same categoryline item or items as other compensation costs and requires the hedged item.other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company only became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 92 to the financial statements for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with the Company's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet its future capital and liquidity needs. See "Sources of Capital" herein for additional information regarding derivatives.on lines of credit.
The Company also anticipates utilizing third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner will take significantly all of the federal tax benefits. These tax equity partnerships are expected to be consolidated in the Company's financial statements using a HLBV methodology to allocate partnership gains and losses to the Company. The Company recently secured third-party tax equity funding for the Cactus Flats project subject to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
achieving commercial operation and various other customary conditions to closing as well as for the Gaskell West 1 project. The ultimate outcome of these matters cannot be determined at this time.
In addition, the Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in the middle of 2018. Proceeds from the sale may be used for debt redemptions, common stock dividends, working capital, and general corporate purposes as well to support the Company's continuing growth strategy.
Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.As of December 31, 2017, the Company had $2.0 billion of unutilized ITCs and PTCs which are not expected to be fully utilized until 2027. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $339 million in 2016, a decrease of $664 million compared to 2015 primarily due to an increase in unutilized ITCs and PTCs.
Net cash used for investing activities totaled $1.6 billion, $4.8 billion, and $2.5 billion in 2017, 2016, and 2015, respectively, and was primarily due to acquisitions and the construction of renewable and natural gas facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests. Net cash provided from financing activities totaled $2.3 billion in 2015 primarily due to the issuance of additional senior notes and a 13-month term loan.
Significant balance sheet changes include a $1.0 billion increase in plant in service primarily due to new solar and wind facilities being acquired or placed in service, a $284 million increase in deferred income taxes primarily due to additional unutilized PTCs, and a $113 million increase in CWIP primarily due to the construction of a new wind facility and the Mankato natural gas expansion project. In addition, ITC benefits that are deferred and amortized over the asset lives increased $45 million as a result of additional ITCs from new solar facilities being placed in service, offset by ongoing ITC amortization. Other significant changes include a $970 million decrease in cash and cash equivalents and a $456 million decrease in acquisitions payable.
Sources of Capital
The Company plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, and equity contributions from Southern Company. The Company also plans to utilize funds resulting from any potential sale of a 33% equity interest in substantially all of its solar asset portfolio, if completed. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, the Company (excluding its subsidiaries) issues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended.
At December 31, 2017, the Company's current liabilities exceeded current assets by $474 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. The Company believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, the debt capital markets, the commercial paper program, and operating cash flows.
The Company obtains financing separately without credit support from any affiliate. To meet liquidity and capital resource requirements, the Company had cash and cash equivalents of approximately $129 million at December 31, 2017.
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. The Company's subsidiaries are not issuers under the commercial paper program.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of commercial paper were as follows:
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 105 |
| | 2.0% | | $ | 232 |
| | 1.4% | | $ | 628 |
|
December 31, 2016 | $ | — |
| | N/A | | $ | 56 |
| | 0.8% | | $ | 310 |
|
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2017, 2016, and 2015. |
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under this Facility to $750 million from $600 million. The Company's subsidiaries are not borrowers under the Facility. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Facility, as well as the Company's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company had $113 million of cash collateral posted related to PPA requirements.
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity, Garland, and Roserock Project Credit Facilities were fully repaid on October 14, 2016, December 29, 2016, and January 31, 2017, respectively.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of the Company assumed a $217 million construction loan, which was fully repaid in September 2016.
Financing Activities
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Other Debt
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes. At December 31, 2017, this outstanding term loan was included in securities due within one year.
In addition, during 2017, the Company issued a total of $21 million in letters of credit under the Company's credit facilities.
Credit Rating Risk
The Company does not offsethave any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 39 |
|
At BBB- and/or Baa3 | $ | 415 |
|
At BB+ and/or Ba1 (*) | $ | 1,118 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
In addition, the Company has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
While it is unclear how the credit rating agencies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by the Company to mitigate the resulting impacts, which, among other alternatives, could include adjusting the Company's capital structure, the Company's credit ratings could be negatively affected.
Market Price Risk
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value amounts recognized for multiple derivative instruments executed within the same counterparty underconsolidated balance sheets as either assets or liabilities and are presented on a master netting arrangement. Additionally,gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
At December 31, 2017, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized$945 million of long-term variable rate notes outstanding. If the Company sustained a 100 basis point change in interest rates for its variable interest rate exposure, the change would effect annualized interest expense by approximately $9 million at December 31, 2015.2017. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.
The Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. The Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Because energy from the Company's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
For the years ended December 31, 2017 and 2016, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were as follows: |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Contracts outstanding at the beginning of period, assets (liabilities), net | $ | 16 |
| $ | 1 |
|
Contracts realized or settled | (17 | ) | (3 | ) |
Current period changes (*) | (9 | ) | 18 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | (10 | ) | $ | 16 |
|
| |
(*) | Current period changes also include changes in the fair value of new contracts entered into during the period, if any. |
For the years ending December 31, 2017 and 2016, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows: |
| | | | | | |
| 2017 | 2016 |
Power – net sold | | |
MWH (in millions) | 3.0 |
| 6.1 |
|
Weighted average contract cost per MWH above (below) market prices (in dollars) | $ | (2.67 | ) | $ | 1.45 |
|
Natural Gas – net purchased | | |
Commodity - mmBtu (in millions) | 14.4 |
| 27.1 |
|
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars) | $ | 0.12 |
| $ | (0.27 | ) |
Gains and losses on energy-related derivatives designated as cash flow hedges which are used by the Company to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 8 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2017 all mature in 2018.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and Note 9 to the financial statements for additional information.
Comprehensive Income
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Capital Requirements and Contractual Obligations
The objectivecapital program of comprehensive incomethe Company is subject to reportperiodic review and revision and is currently estimated to total $7.2 billion over the next five years through 2022. This includes approximately $0.9 billion in committed construction, capital improvements, and work to be performed under LTSAs, totaling approximately $400 million for 2018 and an average of approximately $137 million each year from 2019 through 2022. In addition, the capital program includes a measurefurther $6.3 billion in planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of allnumerous factors such as: changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income,business conditions; changes in the fair valueexpected environmental compliance program; changes in environmental laws and regulations; the outcome of qualifying cash flow hedges,any legal challenges to the environmental rules; changes in FERC rules and reclassificationsregulations; changes in load projections; changes in legislation; the cost and efficiency of amounts includedconstruction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 11 to the financial statements for additional information.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, other purchase commitments, and pension and other postretirement benefit plans are detailed in net income.the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 770 |
| | $ | 1,425 |
| | $ | 977 |
| | $ | 2,630 |
| | $ | 5,802 |
|
Interest | 189 |
| | 334 |
| | 278 |
| | 1,524 |
| | 2,325 |
|
Financial derivative obligations(b) | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Operating leases(c) | 22 |
| | 45 |
| | 45 |
| | 815 |
| | 927 |
|
Purchase commitments — | | | | | | | | | |
Capital(d) | 1,099 |
| | 3,661 |
| | 1,750 |
| | — |
| | 6,510 |
|
Fuel(e) | 453 |
| | 555 |
| | 327 |
| | 56 |
| | 1,391 |
|
Purchased power(f) | 40 |
| | 82 |
| | 42 |
| | — |
| | 164 |
|
Other(g) | 149 |
| | 315 |
| | 216 |
| | 1,770 |
| | 2,450 |
|
Pension and other postretirement benefit plans(h) | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Total | $ | 2,735 |
| | $ | 6,418 |
| | $ | 3,635 |
| | $ | 6,795 |
| | $ | 19,583 |
|
| |
(a) | All amounts are reflected based on final maturity dates and include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is a $77 million gain related to the foreign currency hedge of €1.1 billion. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. |
| |
(b) | For additional information, see Notes 1 and 9 to the financial statements. |
| |
(c) | Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. See Note 7 to the financial statements under "Commitments" for additional information. |
| |
(d) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Included in these amounts are planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year, and may vary materially each year due to market opportunities and the Company's ability to execute its growth strategy. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. |
| |
(e) | Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(f) | Purchased power commitments will be resold under a third party agreement at cost. |
| |
(g) | Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission. |
| |
(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company's business, economic conditions, fuel and environmental cost recovery, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, estimated sales and purchases under power sale and purchase agreements, timing of expected future capacity need in existing markets, completion dates of construction projects, projections for the qualified pension plan and postretirement benefit plans contributions, filings with federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
•transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations;
the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the potential sale of a 33% equity interest in substantially all of the Company's solar assets, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Wholesale revenues, non-affiliates | $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
|
Wholesale revenues, affiliates | 392 |
| | 419 |
| | 417 |
|
Other revenues | 12 |
| | 12 |
| | 9 |
|
Total operating revenues | 2,075 |
| | 1,577 |
| | 1,390 |
|
Operating Expenses: | | | | | |
Fuel | 621 |
| | 456 |
| | 441 |
|
Purchased power | 149 |
| | 102 |
| | 93 |
|
Other operations and maintenance | 386 |
| | 354 |
| | 260 |
|
Depreciation and amortization | 503 |
| | 352 |
| | 248 |
|
Taxes other than income taxes | 48 |
| | 23 |
| | 22 |
|
Total operating expenses | 1,707 |
| | 1,287 |
| | 1,064 |
|
Operating Income | 368 |
| | 290 |
| | 326 |
|
Other Income and (Expense): | | | | | |
Interest expense, net of amounts capitalized | (191 | ) | | (117 | ) | | (77 | ) |
Other income (expense), net | 1 |
| | 6 |
| | 1 |
|
Total other income and (expense) | (190 | ) | | (111 | ) | | (76 | ) |
Earnings Before Income Taxes | 178 |
| | 179 |
| | 250 |
|
Income taxes (benefit) | (939 | ) | | (195 | ) | | 21 |
|
Net Income | 1,117 |
| | 374 |
| | 229 |
|
Less: Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Net Income Attributable to the Company | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $39, $(17), and $-, respectively | 63 |
| | (27 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $(46), $36, and $-, respectively | (73 | ) | | 58 |
| | 1 |
|
Total other comprehensive income (loss) | (10 | ) | | 31 |
| | 1 |
|
Less: Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Comprehensive Income Attributable to the Company | $ | 1,061 |
| | $ | 369 |
| | $ | 216 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 536 |
| | 370 |
| | 254 |
|
Deferred income taxes | (263 | ) | | (1,063 | ) | | 42 |
|
Investment tax credits | — |
| | — |
| | 162 |
|
Amortization of investment tax credits | (57 | ) | | (37 | ) | | (19 | ) |
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Accrued income taxes, non-current | 14 |
| | (109 | ) | | 109 |
|
Income taxes receivable, non-current | (61 | ) | | (13 | ) | | — |
|
Other, net | (9 | ) | | 12 |
| | (2 | ) |
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (60 | ) | | (54 | ) | | 18 |
|
-Other current assets | (4 | ) | | (25 | ) | | (30 | ) |
-Accrued taxes | (55 | ) | | 940 |
| | 269 |
|
-Other current liabilities | 1 |
| | 46 |
| | (29 | ) |
Net cash provided from operating activities | 1,155 |
| | 339 |
| | 1,003 |
|
Investing Activities: | | | | | |
Business acquisitions | (1,032 | ) | | (2,294 | ) | | (1,719 | ) |
Property additions | (268 | ) | | (2,114 | ) | | (1,005 | ) |
Change in construction payables | (153 | ) | | (57 | ) | | 251 |
|
Investment in restricted cash | (16 | ) | | (733 | ) | | (159 | ) |
Distribution of restricted cash | 34 |
| | 736 |
| | 154 |
|
Payments pursuant to LTSAs and for equipment not yet received | (203 | ) | | (350 | ) | | (82 | ) |
Other investing activities | 15 |
| | 15 |
| | 22 |
|
Net cash used for investing activities | (1,623 | ) | | (4,797 | ) | | (2,538 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (104 | ) | | 73 |
| | (58 | ) |
Proceeds — | | | | | |
Capital contributions | — |
| | 1,850 |
| | 646 |
|
Senior notes | 525 |
| | 2,831 |
| | 1,650 |
|
Other long-term debt | 43 |
| | 65 |
| | 402 |
|
Redemptions — | | | | | |
Senior notes | (500 | ) | | (200 | ) | | (525 | ) |
Other long-term debt | (18 | ) | | (86 | ) | | (4 | ) |
Distributions to noncontrolling interests | (119 | ) | | (57 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Purchase of membership interests from noncontrolling interests | (59 | ) | | (129 | ) | | — |
|
Payment of common stock dividends | (317 | ) | | (272 | ) | | (131 | ) |
Other financing activities | (33 | ) | | (30 | ) | | (13 | ) |
Net cash provided from (used for) financing activities | (502 | ) | | 4,727 |
| | 2,290 |
|
Net Change in Cash and Cash Equivalents | (970 | ) | | 269 |
| | 755 |
|
Cash and Cash Equivalents at Beginning of Year | 1,099 |
| | 830 |
| | 75 |
|
Cash and Cash Equivalents at End of Year | $ | 129 |
| | $ | 1,099 |
| | $ | 830 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $11, $44, and $14 capitalized, respectively) | $ | 189 |
| | $ | 89 |
| | $ | 74 |
|
Income taxes (net of refunds and investment tax credits) | (487 | ) | | 116 |
| | (518 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 251 |
| | 257 |
|
Accrued acquisitions at year-end | — |
| | 461 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 129 |
| | $ | 1,099 |
|
Receivables — | | | |
Customer accounts receivable | 117 |
| | 102 |
|
Affiliated | 50 |
| | 57 |
|
Other | 98 |
| | 34 |
|
Materials and supplies | 278 |
| | 337 |
|
Prepaid income taxes | 50 |
| | 74 |
|
Other current assets | 36 |
| | 54 |
|
Total current assets | 758 |
| | 1,757 |
|
Property, Plant, and Equipment: | | | |
In service | 13,755 |
| | 12,728 |
|
Less: Accumulated provision for depreciation | 1,910 |
| | 1,484 |
|
Plant in service, net of depreciation | 11,845 |
| | 11,244 |
|
Construction work in progress | 511 |
| | 398 |
|
Total property, plant, and equipment | 12,356 |
| | 11,642 |
|
Other Property and Investments: | | | |
Intangible assets, net of amortization of $47 and $22 at December 31, 2017 and December 31, 2016, respectively | 411 |
| | 436 |
|
Total other property and investments | 411 |
| | 436 |
|
Deferred Charges and Other Assets: | | | |
Prepaid LTSAs | 118 |
| | 101 |
|
Accumulated deferred income taxes | 925 |
| | 594 |
|
Income taxes receivable, non-current | 72 |
| | 11 |
|
Other deferred charges and assets | 566 |
| | 628 |
|
Total deferred charges and other assets | 1,681 |
| | 1,334 |
|
Total Assets | $ | 15,206 |
| | $ | 15,169 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 770 |
| | $ | 560 |
|
Notes payable | 105 |
| | 209 |
|
Accounts payable — | | | |
Affiliated | 102 |
| | 88 |
|
Other | 103 |
| | 278 |
|
Accrued taxes — | | | |
Accrued income taxes | — |
| | 148 |
|
Other accrued taxes | 4 |
| | 7 |
|
Acquisitions payable | 5 |
| | 461 |
|
Other current liabilities | 143 |
| | 152 |
|
Total current liabilities | 1,232 |
| | 1,903 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.50% due 2018 | — |
| | 350 |
|
1.95% due 2019 | 600 |
| | 600 |
|
2.375% due 2020 | 300 |
| | 300 |
|
2.50% due 2021 | 300 |
| | 300 |
|
1.00% due 2022 | 720 |
| | 632 |
|
1.85% to 5.25% due 2023-2046 | 2,664 |
| | 2,592 |
|
Other long-term debt — | | | |
Variable rate (1.88% at 12/31/17) due 2018 | — |
| | 320 |
|
Variable rate (2.18% at 12/31/17) due 2020 | 525 |
| | — |
|
Variable rate (3.75% at 1/1/17) due 2032-2036 | — |
| | 15 |
|
Unamortized debt premium (discount), net | (10 | ) | | (12 | ) |
Unamortized debt issuance expense | (28 | ) | | (29 | ) |
Long-term debt | 5,071 |
| | 5,068 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 199 |
| | 152 |
|
Accumulated deferred ITCs | 1,884 |
| | 1,839 |
|
Other deferred credits and liabilities | 322 |
| | 368 |
|
Total deferred credits and other liabilities | 2,405 |
| | 2,359 |
|
Total Liabilities | 8,708 |
| | 9,330 |
|
Redeemable Noncontrolling Interests | — |
| | 164 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 3,662 |
| | 3,671 |
|
Retained earnings | 1,478 |
| | 724 |
|
Accumulated other comprehensive income | (2 | ) | | 35 |
|
Total common stockholder's equity | 5,138 |
| | 4,430 |
|
Noncontrolling Interests | 1,360 |
| | 1,245 |
|
Total Stockholders' Equity | 6,498 |
| | 5,675 |
|
Total Liabilities and Stockholders' Equity | $ | 15,206 |
| | $ | 15,169 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income | | Total Common Stockholder's Equity | | Noncontrolling Interests(a) | | Total |
| (in millions) |
Balance at December 31, 2014 | — |
| | $ | — |
| | $ | 1,176 |
| | $ | 573 |
| | $ | 3 |
| | $ | 1,752 |
| | $ | 219 |
| | $ | 1,971 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
|
Capital contributions from parent company | — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
Balance at December 31, 2015 | — |
| | — |
| | 1,822 |
| | 657 |
| | 4 |
| | 2,483 |
| | 781 |
| | 3,264 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 338 |
| | — |
| | 338 |
| | — |
| | 338 |
|
Capital contributions from parent company | — |
| | — |
| | 1,850 |
| | — |
| | — |
| | 1,850 |
| | — |
| | 1,850 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 31 |
| | 31 |
| | — |
| | 31 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (272 | ) | | — |
| | (272 | ) | | — |
| | (272 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| | 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Other | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | — |
| | — |
|
Balance at December 31, 2016 | — |
| | — |
| | 3,671 |
| | 724 |
| | 35 |
| | 4,430 |
| | 1,245 |
| | 5,675 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
|
Capital contributions from parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | (10 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (317 | ) | | — |
| | (317 | ) | | — |
| | (317 | ) |
Other comprehensive income transfer from SCS (b) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | (27 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | | (122 | ) |
Net income attributable to noncontrolling interests | �� |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
Other | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | — |
| | $ | — |
| | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
|
| |
(a) | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
(b) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Variable Interest Entities1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies.
Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis.
The primary beneficiarypreparation of consolidated financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform to the current year presentation.
The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activitiesfive-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the VIE that most significantly impactnew standard is to recognize revenue to depict the VIE's economic performancetransfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the obligation to absorb losses or the right to receive benefitsrelated cash flows arising from the VIE that could potentially be significant to the VIE.contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain wholly-owned subsidiariescapacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that are determined to be VIEs. would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is consideredcurrently implementing an information technology system along with the primary beneficiary of these VIEs because itrelated changes to internal controls and accounting policies that will support the most significant activities ofaccounting for leases under ASU 2016-02. In addition, the VIEs, including operatingCompany has substantially completed a detailed inventory and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extentanalysis of its equity interests.
2. ACQUISITIONS
During 2015 and 2014, in accordance withleases where the Company's overall growth strategy, the Company acquired or contractedmajority relate to acquire throughland leases for its wholly-owned subsidiaries, SRP or SRE, the projects set forth in the following table. Acquisition-related costs of approximately $4 million were expensed as incurred. The acquisitions do not include any contingent consideration unless specifically noted.renewable generation
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
2015In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements. |
| | | | | | | | | | | | | |
Project Facility | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Percentage Ownership | | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period | Approx. Purchase Price | |
| | (MW) | | | | | | | (in millions) | |
WIND |
Kay Wind | Apex Clean Energy Holdings, LLC December 11, 2015 | 299 | Kay County, OK | 100 | % | | December 12, 2015 | Westar Energy, Inc. and Grant River Dam Authority | 20 years | $ | 481 |
| (b) |
| | | | | | | | | | |
Grant Wind | Apex Clean Energy Holdings, LLC | 151 | Grant County, OK | 100 | % | | March 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | $ | 258 |
| (c) |
SOLAR |
Lost Hills Blackwell | First Solar April 15, 2015 | 33 | Kern County, CA | 51 | % | (a) | April 17, 2015 | City of Roseville, California/Pacific Gas and Electric Company | 29 years | $ | 73 |
| (d) |
| | | | | | | | | | |
North Star | First Solar April 30, 2015 | 61 | Fresno County, CA | 51 | % | (a) | June 20, 2015 | Pacific Gas and Electric Company | 20 years | $ | 208 |
| (e) |
| | | | | | | | | | |
Tranquillity | Recurrent Energy, LLC August 28, 2015 | 205 | Fresno County, CA | 51 | % | (a) | Fourth quarter 2016 | Shell Energy North America (US), LP and then SCE | 18 years | $ | 100 |
| (f) |
| | | | | | | | | | |
Desert Stateline | First Solar August 31, 2015 | 299 | San Bernardino County, CA | 51 | % | (a) | From December 2015 to third quarter 2016 (h) | SCE | 20 years | $ | 439 |
| (g) |
| | | | | | | | | | |
Morelos | Solar Frontier Americas Holding, LLC October 22, 2015 | 15 | Kern County, CA | 90 | % | | November 25, 2015 | Pacific Gas and Electric Company | 20 years | $ | 45 |
| (i) |
| | | | | | | | | | |
Roserock | Recurrent Energy, LLC November 23, 2015 | 160 | Pecos County, TX | 51 | % | (a) | Fourth quarter 2016 | Austin Energy | 20 years | $ | 45 |
| (j) |
| | | | | | | | | | |
Garland and Garland A | Recurrent Energy, LLC December 17, 2015 | 205 | Kern County, CA | 51 | % | (a) | Fourth quarter 2016 | SCE | 15 years and 20 years | $ | 49 |
| (k) |
| | | | | | | | | | |
Calipatria | Solar Frontier Americas Holding, LLC February 11, 2016 | 20 | Imperial County, CA | 90 | % | | February 11, 2016 | San Diego Gas & Electric Company | 20 years | $ | 52 |
| (l) |
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information. | |
(a) | The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitledOn August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. Affiliate Transactions Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million, $258 million, and $219 million for the years ended December 31, 2017, 2016, and 2015, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015. The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million, $193 million, and $146 million for the years ended December 31, 2017, 2016, and 2015, respectively. Of these costs, $192 million, $173 million, and $138 million for the years ended December 31, 2017, 2016, and 2015, respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015. The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. At each acquisition, the Company acquired a controlling interest in the entity owning the project facility and recorded approximately $227 million for the noncontrolling interests, in the aggregate, which is recorded as a non-cash transaction in contributions from noncontrolling interests and plant acquisitions. |
| |
(b) | Kay Wind - The total purchase price, including $35 million of contingent consideration, is approximately $481 million. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $481 million as CWIP, $8 million as a receivable related to transmission interconnection costs, and $8 million as payables; however, the allocation of the purchase price to individual assets has not been finalized.
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(c) | Grant Wind - On September 4, 2015, Southern Power entered into an agreement to acquire Grant Wind, LLC. The completion of the acquisition is subject to the seller achieving certain construction and project milestones as well as various other customary conditions to closing. The acquisition is expected to close at or near the expected COD. The purchase price includes approximately $24 million of contingent consideration and may be adjusted based on performance testing and production over the first 10 years of operation. The ultimate outcome of this matter cannot be determined at this time.
|
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| |
(d) | Lost Hills Blackwell - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $34 million. At the acquisition date, the members became contingently obligated to pay $3 million of construction payables through COD, making the aggregate purchase price approximately $107 million. The fair values of the assets acquired through the business combination were recorded as follows: $105 million as property, plant, and equipment, $3 million as a receivable related to transmission interconnection costs, and $4 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized.
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| |
(e) | North Star - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $99 million. At the acquisition date, the members became contingently obligated to pay $233 million of construction payables through COD, making the aggregate purchase price approximately $307 million. The fair values of the assets acquired through the business combination were recorded as follows: $266 million as property, plant, and equipment, $25 million as an intangible asset, $21 million as a receivable related to transmission interconnection costs, and $238 million as construction and other payables; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The amortization expense for the year ended December 31, 2015 was $1 million. The estimated amortization for future periods is approximately $1.2 million per year for 2016 through 2020, and $18 million thereafter.
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(f) | Tranquillity - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $173 million of assets and receiving an initial distribution of $100 million. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $186 million as CWIP, $24 million as other receivables, and $37 million as payables; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $473 million to $493 million. The ultimate outcome of this matter cannot be determined at this time.
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| |
(g) | Desert Stateline - Concurrent with the acquisition, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests for approximately $223 million. As of December 31, 2015, the fair values of the assets acquired through the business combination, which includes the Company's and First Solar's initial payments due under the related construction agreement, were recorded as follows: $413 million as CWIP and $249 million as an intangible asset; however, the allocation of the purchase price to individual assets has not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $6.2 million in 2016, $12.5 million per year for 2017 through 2020, and $192.8 million thereafter. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $1.2 billion to $1.3 billion. The ultimate outcome of this matter cannot be determined at this time.
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(h) | Desert Stateline - The first three of eight phases were placed in service in December 2015. Subsequent to December 31, 2015, phases four and five were placed in service.
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(i) | Morelos - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $50 million. As of December 31, 2015, the fair values of the assets acquired through the business combination were recorded as follows: $49 million as property, plant, and equipment and $1 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized.
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(j) | Roserock - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $26 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $75 million as CWIP, $6 million as other receivables, and $10 million as payables and accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $333 million to $353 million. The ultimate outcome of this matter cannot be determined at this time.
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(k) | Garlandand Garland A - Concurrent with the acquisition, a wholly-owned subsidiary of Recurrent Energy, LLC converted all its membership interests to 100% of the class B membership interests after contributing approximately $31 million of assets. As of December 31, 2015, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $107 million as CWIP, $1 million as other deferred assets, and $28 million as payables and other accrued expenses; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $532 million to $552 million. The ultimate outcome of this matter cannot be determined at this time.
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(l) | Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest, is approximately $58 million.
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Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The aggregate amount of revenue recognized byinterstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions sincethat meet the variousdefinition of a business, the Company includes operating results from the date of acquisition dates, includedin its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statementstatements of incomeincome. See Note 8 for 2015 is $18 million. additional fair value information.
Revenues
The aggregateCompany sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount of net income, excludingor the impacts of ITCs, attributable toamount billable under the Company related tocontract over the acquisitions, sincerespective contract periods. When multiple contracts exist with the various acquisition dates,same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in wholesale revenues.
The Company may also enter into contracts to sell short-term capacity in the consolidated statement of incomewholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for additional information.
Energy revenues and other contingent revenues are recognized in the period the energy is immaterial. These businesses did not havedelivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues or activities prior to their assets being constructed and placed in service; and therefore, supplemental proforma information as though the acquisitions occurred as of the beginning of 2015, andrevenues. See "Financial Instruments" herein for the comparable 2014 year is not meaningful and has been omitted.additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
2014Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the Company's top three customers for each of the years presented:
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Project Facility | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Percentage Ownership |
| COD | PPA Counterparties for Plant Output | PPA Contract Period | Approx. Purchase Price |
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| (MW) |
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|
|
|
| (in millions) |
|
SOLAR |
Adobe | Sun Edison, LLC April 17, 2014 | 20 | Kern County, CA | 90 | % |
| May 21, 2014 | SCE | 20 years | $ | 86 |
| (b) |
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Macho Springs | First Solar Development, LLC May 22, 2014 | 50 | Luna County, NM | 90 | % |
| May 23, 2014 | EPE | 20 years | $ | 117 |
| (c) |
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Imperial Valley | First Solar, October 22, 2014 | 150 | Imperial County, CA | 51 | % | (a) | November 26, 2014 | San Diego Gas & Electric Company | 25 years | $ | 505 |
| (d) |
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| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Georgia Power | 11.3 | % | | 16.5 | % | | 15.8 | % |
Duke Energy Corporation | 6.7 | % | | 7.8 | % | | 8.2 | % |
Morgan Stanley Capital Group | 4.5 | % | | N/A |
| | N/A |
|
San Diego Gas & Electric Company | N/A |
| | 5.7 | % | | N/A |
|
Florida Power & Light Company | N/A |
| | N/A |
| | 10.7 | % |
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(a) | The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. |
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(b) | Adobe - Total purchase price, including the minority owner TRE's 10% ownership interest, was $97 million. The fair values of the assets acquired were ultimately recorded as follows: $84 million to property, plant, and equipment, $15 million to prepayment related to transmission services, and $6 million to PPA intangible, resulting in a $5 million bargain purchase gain and a $3 million deferred tax liability. The bargain purchase gain is included in other income (expense), net. Acquisition-related costs were expensed as incurred and were not material.Fuel Costs Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. Development Costs The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income. Income and Other Taxes The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information. Property, Plant, and Equipment The Company's depreciable property, plant, and equipment consists primarily of generation assets. Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred. When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income. Depreciation The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of- |
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(c) | Macho Springs -Total purchase price, including the minority owner TRE's 10% ownership interest, was $130 million. The fair values of the assets acquired were ultimately recorded as follows: $128 million to property, plant, and equipment, $1 million to prepaid property taxes, and $1 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.
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(d) | Imperial Valley - In connection with this acquisition, SG2 Holdings, LLC (SG2 Holdings) made an aggregate payment of approximately $128 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved in November 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by the Company for the acquisition of Imperial Valley was approximately $505 million in addition to the $223 million noncash contribution by the minority member. The fair values of the assets acquired were ultimately recorded as follows: $708 million to property, plant, and equipment and $20 million to prepayment related to transmission services. Acquisition-related costs were expensed as incurred and were not material.
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NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:
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Generating facility | Useful life |
Natural gas | Up to 45 years |
Biomass | Up to 40 years |
Solar | Up to 35 years |
Wind | Up to 30 years |
The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.
Asset Retirement Obligations
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability.
Details of the AROs included on the consolidated balance sheets are as follows:
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| 2017 | | | 2016 | |
| (in millions) | |
Balance at beginning of year | $ | 64 |
| | | $ | 21 |
| |
Liabilities incurred | 6 |
| | | 42 |
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Accretion | 4 |
| | | 1 |
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Cash flow revisions | 4 |
| | | — |
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Balance at end of year | $ | 78 |
| | | $ | 64 |
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Long-Term Service Agreements
The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated statements of cash flows.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded.
Amortization expense for acquired PPAs was $25 million, $10 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for each of the next five years.
Transmission Receivables/Prepayments
As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
Construction Projects
Construction Projects Completed and in Progress
During 2015,2017, in accordance with the Company'sits overall growth strategy, the Company constructedcompleted construction of and placed in service, or commencedcontinued construction of, the projects set forth in the table below,below.
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Project Facility | Resource | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual / Expected COD | PPA Counterparties | PPA Contract Period |
Construction Projects Completed During the Year Ended December 31, 2017 |
East Pecos | Solar | 120 | | Pecos County, TX | 100 | % | | March 2017 | Austin Energy | 15 years |
Lamesa | Solar | 102 | | Dawson County, TX | 100 | % | | April 2017 | City of Garland, Texas | 15 years |
Projects Under Construction at December 31, 2017 |
Cactus Flats | Wind | 148 | | Concho County, TX | 100 | % | (*) | Third quarter 2018 | General Motors and General Mills | 12 years and 15 years |
Mankato Expansion | Natural Gas | 345 | | Mankato, MN | 100% |
| | Second quarter 2019 | Northern States Power Company | 20 years |
(*) On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in additionservice, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the Tranquillity, Desert Stateline, Roserock, Garland,class B membership interests.
Total aggregate construction costs for projects under construction at December 31, 2017, excluding acquisition costs and Garland A facilities. Total costincluding construction costs to complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and $430 million. At December 31, 2017, total costs of construction incurred for these projects during 2015 was $1.8 billion,$188 million, all of which $1.1 billionremained in CWIP.
Development Projects
During 2017, as part of the Company's renewable development strategy, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
During 2016, the Company entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the Company filed a request for rehearing and filed their response with the FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in CWIPresponse to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business. The Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as standards for air, water, land, and protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Revenue Recognition
The Company's revenue recognition depends on appropriate classification and documentation of transactions in accordance with GAAP. In general, the Company's power sale transactions, which include PPAs, can be classified in one of four categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Notes 1 and 9 to the financial statements. The Company's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract.
Lease Transactions
The Company considers the following factors to determine whether the sales contract is a lease:
Assessing whether specific property is explicitly or implicitly identified in the agreement;
Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and
Assessing whether the arrangement conveys to the purchaser the right to use the identified property.
If the contract meets the above criteria for a lease, the Company performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of the Company's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in the Company's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered.
Non-Derivative and Normal Sale Derivative Transactions
If the power sales contract is not classified as a lease, the Company further considers the following factors to determine proper classification:
Assessing whether the contract meets the definition of a derivative;
Assessing whether the contract meets the definition of a capacity contract;
Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and
Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within the Company's available generating capacity) are accounted for as executory contracts. The related capacity revenue, if any, is recognized on an accrual basis in amounts equal to the lesser of the cumulative levelized amount or the cumulative amount billable under the contract over the respective contract periods. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered.
Cash Flow Hedge Transactions
The Company further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:
Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and
Assessing hedge effectiveness at inception and throughout the contract term.
These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.
Mark-to-Market Transactions
Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues.
Impairment of Long-Lived Assets and Intangibles
The Company's investments in long-lived assets are primarily generation assets, whether in service or under construction. The Company's intangible assets arise from certain acquisitions and consist of acquired PPAs, which are amortized to revenue over the term of the respective PPAs. The Company evaluates the carrying value of these assets whenever indicators of potential impairment exist. Examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, and the inability to remarket generating capacity for an extended period. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:
Future demand for electricity based on projections of economic growth and estimates of available generating capacity;
Future power and natural gas prices, which have been quite volatile in recent years; and
Future operating costs.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 to the financial statements for additional fair value information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note and 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company only became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 to the financial statements for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2015.2017. The Company's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with the Company's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through debt issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet its future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
The Company also anticipates utilizing third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner will take significantly all of the federal tax benefits. These tax equity partnerships are expected to be consolidated in the Company's financial statements using a HLBV methodology to allocate partnership gains and losses to the Company. The Company recently secured third-party tax equity funding for the Cactus Flats project subject to
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
achieving commercial operation and various other customary conditions to closing as well as for the Gaskell West 1 project. The ultimate outcome of these matters cannot be determined at this time.
In addition, the Company is pursuing the sale of a 33% equity interest in a newly-formed holding company that owns substantially all of the Company's solar assets, which, if successful, is expected to close in the middle of 2018. Proceeds from the sale may be used for debt redemptions, common stock dividends, working capital, and general corporate purposes as well to support the Company's continuing growth strategy.
Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.As of December 31, 2017, the Company had $2.0 billion of unutilized ITCs and PTCs which are not expected to be fully utilized until 2027. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $339 million in 2016, a decrease of $664 million compared to 2015 primarily due to an increase in unutilized ITCs and PTCs.
Net cash used for investing activities totaled $1.6 billion, $4.8 billion, and $2.5 billion in 2017, 2016, and 2015, respectively, and was primarily due to acquisitions and the construction of renewable and natural gas facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests. Net cash provided from financing activities totaled $2.3 billion in 2015 primarily due to the issuance of additional senior notes and a 13-month term loan.
Significant balance sheet changes include a $1.0 billion increase in plant in service primarily due to new solar and wind facilities being acquired or placed in service, a $284 million increase in deferred income taxes primarily due to additional unutilized PTCs, and a $113 million increase in CWIP primarily due to the construction of a new wind facility and the Mankato natural gas expansion project. In addition, ITC benefits that are deferred and amortized over the asset lives increased $45 million as a result of additional ITCs from new solar facilities being placed in service, offset by ongoing ITC amortization. Other significant changes include a $970 million decrease in cash and cash equivalents and a $456 million decrease in acquisitions payable.
Sources of Capital
The Company plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, and equity contributions from Southern Company. The Company also plans to utilize funds resulting from any potential sale of a 33% equity interest in substantially all of its solar asset portfolio, if completed. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, the Company (excluding its subsidiaries) issues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended.
At December 31, 2017, the Company's current liabilities exceeded current assets by $474 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. The Company believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, the debt capital markets, the commercial paper program, and operating cash flows.
The Company obtains financing separately without credit support from any affiliate. To meet liquidity and capital resource requirements, the Company had cash and cash equivalents of approximately $129 million at December 31, 2017.
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. The Company's subsidiaries are not issuers under the commercial paper program.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Details of commercial paper were as follows:
|
| | | | | | | | | | | | |
Solar Facility | Seller | Approx. Nameplate Capacity | County Location in Georgia | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period | Estimated Construction Cost | |
| | (MW) | | | | | (in millions) | |
Sandhills | N/A | 146 | Taylor | Fourth quarter 2016 | Cobb, Flint, and Sawnee EMCs | 25 years | $ | 260 |
| - | 280 | |
Decatur Parkway | TradeWind Energy, Inc. | 84 | Decatur | December 31, 2015 | Georgia Power(a) | 25 years | Approx. $169 | (c) |
Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 29, 2015 | Georgia Power | 20 years | Approx. $46 | (c) |
Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | Fourth quarter 2016 | Georgia Power(b) | 30 years | $ | 220 |
| - | 230 | (c) |
Pawpaw | Longview Solar, LLC | 30 | Taylor | March 2016 | Georgia Power(a) | 30 years | $ | 70 |
| - | 80 | (c) |
Butler Solar Farm | Strata Solar Development, LLC | 22 | Taylor | February 10, 2016 | Georgia Power | 20 years | Approx. $45 | (c) |
|
| | | | | | | | | | | | | | | |
| Commercial Paper at the End of the Period | | Commercial Paper During the Period (*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
December 31, 2017 | $ | 105 |
| | 2.0% | | $ | 232 |
| | 1.4% | | $ | 628 |
|
December 31, 2016 | $ | — |
| | N/A | | $ | 56 |
| | 0.8% | | $ | 310 |
|
December 31, 2015 | $ | — |
| | N/A | | $ | 166 |
| | 0.5% | | $ | 385 |
|
| |
(*) | Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2017, 2016, and 2015. |
Company Credit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In May 2017, the Company amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased the Company's borrowing ability under this Facility to $750 million from $600 million. The Company's subsidiaries are not borrowers under the Facility. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. Subject to applicable market conditions, the Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Facility, as well as the Company's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of the Company. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. The Company is currently in compliance with all covenants in the Facility.
The Company also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and $19 million remains unused. The Company's subsidiaries are not parties to this letter of credit facility.
In addition, at both December 31, 2017 and 2016, the Company had $113 million of cash collateral posted related to PPA requirements.
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity, Garland, and Roserock Project Credit Facilities were fully repaid on October 14, 2016, December 29, 2016, and January 31, 2017, respectively.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of the Company assumed a $217 million construction loan, which was fully repaid in September 2016.
Financing Activities
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Other Debt
In September 2017, the Company amended its $60 million aggregate principal amount floating rate term loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes. At December 31, 2017, this outstanding term loan was included in securities due within one year.
In addition, during 2017, the Company issued a total of $21 million in letters of credit under the Company's credit facilities.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at December 31, 2017 were as follows:
|
| | | |
Credit Ratings | Maximum Potential Collateral Requirements |
| (in millions) |
At BBB and/or Baa2 | $ | 39 |
|
At BBB- and/or Baa3 | $ | 415 |
|
At BB+ and/or Ba1 (*) | $ | 1,118 |
|
| |
(*) | Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million. |
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
In addition, the Company has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of the Company's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company) from stable to negative.
While it is unclear how the credit rating agencies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by the Company to mitigate the resulting impacts, which, among other alternatives, could include adjusting the Company's capital structure, the Company's credit ratings could be negatively affected.
Market Price Risk
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
At December 31, 2017, the Company had $945 million of long-term variable rate notes outstanding. If the Company sustained a 100 basis point change in interest rates for its variable interest rate exposure, the change would effect annualized interest expense by approximately $9 million at December 31, 2017. Since a significant portion of outstanding indebtedness bears interest at fixed rates, the Company is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.
The Company had foreign currency denominated debt of €1.1 billion at December 31, 2017. The Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.
Because energy from the Company's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, the Company's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
For the years ended December 31, 2017 and 2016, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were as follows: |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Contracts outstanding at the beginning of period, assets (liabilities), net | $ | 16 |
| $ | 1 |
|
Contracts realized or settled | (17 | ) | (3 | ) |
Current period changes (*) | (9 | ) | 18 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | (10 | ) | $ | 16 |
|
| |
(*) | Current period changes also include changes in the fair value of new contracts entered into during the period, if any. |
For the years ending December 31, 2017 and 2016, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows: |
| | | | | | |
| 2017 | 2016 |
Power – net sold | | |
MWH (in millions) | 3.0 |
| 6.1 |
|
Weighted average contract cost per MWH above (below) market prices (in dollars) | $ | (2.67 | ) | $ | 1.45 |
|
Natural Gas – net purchased | | |
Commodity - mmBtu (in millions) | 14.4 |
| 27.1 |
|
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars) | $ | 0.12 |
| $ | (0.27 | ) |
Gains and losses on energy-related derivatives designated as cash flow hedges which are used by the Company to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
The Company uses over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 8 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2017 all mature in 2018.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and Note 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Capital Requirements and Contractual Obligations
The capital program of the Company is subject to periodic review and revision and is currently estimated to total $7.2 billion over the next five years through 2022. This includes approximately $0.9 billion in committed construction, capital improvements, and work to be performed under LTSAs, totaling approximately $400 million for 2018 and an average of approximately $137 million each year from 2019 through 2022. In addition, the capital program includes a further $6.3 billion in planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and the Company's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 11 to the financial statements for additional information.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, other purchase commitments, and pension and other postretirement benefit plans are detailed in the contractual obligations table that follows. See Notes 1, 2, 5, 6, 7, and 9 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 770 |
| | $ | 1,425 |
| | $ | 977 |
| | $ | 2,630 |
| | $ | 5,802 |
|
Interest | 189 |
| | 334 |
| | 278 |
| | 1,524 |
| | 2,325 |
|
Financial derivative obligations(b) | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Operating leases(c) | 22 |
| | 45 |
| | 45 |
| | 815 |
| | 927 |
|
Purchase commitments — | | | | | | | | | |
Capital(d) | 1,099 |
| | 3,661 |
| | 1,750 |
| | — |
| | 6,510 |
|
Fuel(e) | 453 |
| | 555 |
| | 327 |
| | 56 |
| | 1,391 |
|
Purchased power(f) | 40 |
| | 82 |
| | 42 |
| | — |
| | 164 |
|
Other(g) | 149 |
| | 315 |
| | 216 |
| | 1,770 |
| | 2,450 |
|
Pension and other postretirement benefit plans(h) | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Total | $ | 2,735 |
| | $ | 6,418 |
| | $ | 3,635 |
| | $ | 6,795 |
| | $ | 19,583 |
|
| |
(a) | Affiliate PPA approved byAll amounts are reflected based on final maturity dates and include the FERC.effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is a $77 million gain related to the foreign currency hedge of €1.1 billion. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. |
| |
(b) | Affiliate PPA subjectFor additional information, see Notes 1 and 9 to FERC approval.the financial statements. |
| |
(c) | Operating lease commitments include certain land leases for solar and wind facilities that are subject to annual price escalation based on indices. See Note 7 to the financial statements under "Commitments" for additional information. |
| |
(d) | The Company provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Included in these amounts are planned expenditures for plant acquisitions and placeholder growth, which averages approximately $1.3 billion per year, and may vary materially each year due to market opportunities and the Company's ability to execute its growth strategy. Amounts represent current estimates of total expenditures, excluding capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2017, significant purchase commitments were outstanding in connection with the construction program. |
| |
(e) | Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the New York Mercantile Exchange future prices at December 31, 2017. |
| |
(f) | Purchased power commitments will be resold under a third party agreement at cost. |
| |
(g) | Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the acquisition priceSouthern Company system's current tariff rate for point-to-point transmission. |
| |
(h) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of all outstanding membership interests ofwhich will be made from the respective development entity.Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the strategic goals for the Company's business, economic conditions, fuel and environmental cost recovery, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, estimated sales and purchases under power sale and purchase agreements, timing of expected future capacity need in existing markets, completion dates of construction projects, projections for the qualified pension plan and postretirement benefit plans contributions, filings with federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for electricity, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
•transmission constraints;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of generating facilities, to construct facilities in accordance with the requirements of permits and licenses, and to satisfy any environmental performance standards, including the requirements of tax credits and other incentives;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations;
the ability to successfully operate generating facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the potential sale of a 33% equity interest in substantially all of the Company's solar assets, which cannot be assured to be completed or beneficial to the Company;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
the ability of the Company to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Revenues: | | | | | |
Wholesale revenues, non-affiliates | $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
|
Wholesale revenues, affiliates | 392 |
| | 419 |
| | 417 |
|
Other revenues | 12 |
| | 12 |
| | 9 |
|
Total operating revenues | 2,075 |
| | 1,577 |
| | 1,390 |
|
Operating Expenses: | | | | | |
Fuel | 621 |
| | 456 |
| | 441 |
|
Purchased power | 149 |
| | 102 |
| | 93 |
|
Other operations and maintenance | 386 |
| | 354 |
| | 260 |
|
Depreciation and amortization | 503 |
| | 352 |
| | 248 |
|
Taxes other than income taxes | 48 |
| | 23 |
| | 22 |
|
Total operating expenses | 1,707 |
| | 1,287 |
| | 1,064 |
|
Operating Income | 368 |
| | 290 |
| | 326 |
|
Other Income and (Expense): | | | | | |
Interest expense, net of amounts capitalized | (191 | ) | | (117 | ) | | (77 | ) |
Other income (expense), net | 1 |
| | 6 |
| | 1 |
|
Total other income and (expense) | (190 | ) | | (111 | ) | | (76 | ) |
Earnings Before Income Taxes | 178 |
| | 179 |
| | 250 |
|
Income taxes (benefit) | (939 | ) | | (195 | ) | | 21 |
|
Net Income | 1,117 |
| | 374 |
| | 229 |
|
Less: Net income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Net Income Attributable to the Company | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Net Income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Other comprehensive income (loss): | | | | | |
Qualifying hedges: | | | | | |
Changes in fair value, net of tax of $39, $(17), and $-, respectively | 63 |
| | (27 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $(46), $36, and $-, respectively | (73 | ) | | 58 |
| | 1 |
|
Total other comprehensive income (loss) | (10 | ) | | 31 |
| | 1 |
|
Less: Comprehensive income attributable to noncontrolling interests | 46 |
| | 36 |
| | 14 |
|
Comprehensive Income Attributable to the Company | $ | 1,061 |
| | $ | 369 |
| | $ | 216 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2015 |
|
| (in millions) |
Operating Activities: | | | | | |
Net income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Adjustments to reconcile net income to net cash provided from operating activities — | | | | | |
Depreciation and amortization, total | 536 |
| | 370 |
| | 254 |
|
Deferred income taxes | (263 | ) | | (1,063 | ) | | 42 |
|
Investment tax credits | — |
| | — |
| | 162 |
|
Amortization of investment tax credits | (57 | ) | | (37 | ) | | (19 | ) |
Collateral deposits | (4 | ) | | (102 | ) | | — |
|
Accrued income taxes, non-current | 14 |
| | (109 | ) | | 109 |
|
Income taxes receivable, non-current | (61 | ) | | (13 | ) | | — |
|
Other, net | (9 | ) | | 12 |
| | (2 | ) |
Changes in certain current assets and liabilities — | | | | | |
-Receivables | (60 | ) | | (54 | ) | | 18 |
|
-Other current assets | (4 | ) | | (25 | ) | | (30 | ) |
-Accrued taxes | (55 | ) | | 940 |
| | 269 |
|
-Other current liabilities | 1 |
| | 46 |
| | (29 | ) |
Net cash provided from operating activities | 1,155 |
| | 339 |
| | 1,003 |
|
Investing Activities: | | | | | |
Business acquisitions | (1,032 | ) | | (2,294 | ) | | (1,719 | ) |
Property additions | (268 | ) | | (2,114 | ) | | (1,005 | ) |
Change in construction payables | (153 | ) | | (57 | ) | | 251 |
|
Investment in restricted cash | (16 | ) | | (733 | ) | | (159 | ) |
Distribution of restricted cash | 34 |
| | 736 |
| | 154 |
|
Payments pursuant to LTSAs and for equipment not yet received | (203 | ) | | (350 | ) | | (82 | ) |
Other investing activities | 15 |
| | 15 |
| | 22 |
|
Net cash used for investing activities | (1,623 | ) | | (4,797 | ) | | (2,538 | ) |
Financing Activities: | | | | | |
Increase (decrease) in notes payable, net | (104 | ) | | 73 |
| | (58 | ) |
Proceeds — | | | | | |
Capital contributions | — |
| | 1,850 |
| | 646 |
|
Senior notes | 525 |
| | 2,831 |
| | 1,650 |
|
Other long-term debt | 43 |
| | 65 |
| | 402 |
|
Redemptions — | | | | | |
Senior notes | (500 | ) | | (200 | ) | | (525 | ) |
Other long-term debt | (18 | ) | | (86 | ) | | (4 | ) |
Distributions to noncontrolling interests | (119 | ) | | (57 | ) | | (18 | ) |
Capital contributions from noncontrolling interests | 80 |
| | 682 |
| | 341 |
|
Purchase of membership interests from noncontrolling interests | (59 | ) | | (129 | ) | | — |
|
Payment of common stock dividends | (317 | ) | | (272 | ) | | (131 | ) |
Other financing activities | (33 | ) | | (30 | ) | | (13 | ) |
Net cash provided from (used for) financing activities | (502 | ) | | 4,727 |
| | 2,290 |
|
Net Change in Cash and Cash Equivalents | (970 | ) | | 269 |
| | 755 |
|
Cash and Cash Equivalents at Beginning of Year | 1,099 |
| | 830 |
| | 75 |
|
Cash and Cash Equivalents at End of Year | $ | 129 |
| | $ | 1,099 |
| | $ | 830 |
|
Supplemental Cash Flow Information: | | | | | |
Cash paid (received) during the period for — | | | | | |
Interest (net of $11, $44, and $14 capitalized, respectively) | $ | 189 |
| | $ | 89 |
| | $ | 74 |
|
Income taxes (net of refunds and investment tax credits) | (487 | ) | | 116 |
| | (518 | ) |
Noncash transactions — | | | | | |
Accrued property additions at year-end | 32 |
| | 251 |
| | 257 |
|
Accrued acquisitions at year-end | — |
| | 461 |
| | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Assets | 2017 |
| | 2016 |
|
| (in millions) |
Current Assets: | | | |
Cash and cash equivalents | $ | 129 |
| | $ | 1,099 |
|
Receivables — | | | |
Customer accounts receivable | 117 |
| | 102 |
|
Affiliated | 50 |
| | 57 |
|
Other | 98 |
| | 34 |
|
Materials and supplies | 278 |
| | 337 |
|
Prepaid income taxes | 50 |
| | 74 |
|
Other current assets | 36 |
| | 54 |
|
Total current assets | 758 |
| | 1,757 |
|
Property, Plant, and Equipment: | | | |
In service | 13,755 |
| | 12,728 |
|
Less: Accumulated provision for depreciation | 1,910 |
| | 1,484 |
|
Plant in service, net of depreciation | 11,845 |
| | 11,244 |
|
Construction work in progress | 511 |
| | 398 |
|
Total property, plant, and equipment | 12,356 |
| | 11,642 |
|
Other Property and Investments: | | | |
Intangible assets, net of amortization of $47 and $22 at December 31, 2017 and December 31, 2016, respectively | 411 |
| | 436 |
|
Total other property and investments | 411 |
| | 436 |
|
Deferred Charges and Other Assets: | | | |
Prepaid LTSAs | 118 |
| | 101 |
|
Accumulated deferred income taxes | 925 |
| | 594 |
|
Income taxes receivable, non-current | 72 |
| | 11 |
|
Other deferred charges and assets | 566 |
| | 628 |
|
Total deferred charges and other assets | 1,681 |
| | 1,334 |
|
Total Assets | $ | 15,206 |
| | $ | 15,169 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | |
Liabilities and Stockholders' Equity | 2017 |
| | 2016 |
|
| (in millions) |
Current Liabilities: | | | |
Securities due within one year | $ | 770 |
| | $ | 560 |
|
Notes payable | 105 |
| | 209 |
|
Accounts payable — | | | |
Affiliated | 102 |
| | 88 |
|
Other | 103 |
| | 278 |
|
Accrued taxes — | | | |
Accrued income taxes | — |
| | 148 |
|
Other accrued taxes | 4 |
| | 7 |
|
Acquisitions payable | 5 |
| | 461 |
|
Other current liabilities | 143 |
| | 152 |
|
Total current liabilities | 1,232 |
| | 1,903 |
|
Long-Term Debt: | | | |
Senior notes — | | | |
1.50% due 2018 | — |
| | 350 |
|
1.95% due 2019 | 600 |
| | 600 |
|
2.375% due 2020 | 300 |
| | 300 |
|
2.50% due 2021 | 300 |
| | 300 |
|
1.00% due 2022 | 720 |
| | 632 |
|
1.85% to 5.25% due 2023-2046 | 2,664 |
| | 2,592 |
|
Other long-term debt — | | | |
Variable rate (1.88% at 12/31/17) due 2018 | — |
| | 320 |
|
Variable rate (2.18% at 12/31/17) due 2020 | 525 |
| | — |
|
Variable rate (3.75% at 1/1/17) due 2032-2036 | — |
| | 15 |
|
Unamortized debt premium (discount), net | (10 | ) | | (12 | ) |
Unamortized debt issuance expense | (28 | ) | | (29 | ) |
Long-term debt | 5,071 |
| | 5,068 |
|
Deferred Credits and Other Liabilities: | | | |
Accumulated deferred income taxes | 199 |
| | 152 |
|
Accumulated deferred ITCs | 1,884 |
| | 1,839 |
|
Other deferred credits and liabilities | 322 |
| | 368 |
|
Total deferred credits and other liabilities | 2,405 |
| | 2,359 |
|
Total Liabilities | 8,708 |
| | 9,330 |
|
Redeemable Noncontrolling Interests | — |
| | 164 |
|
Common Stockholder's Equity: | | | |
Common stock, par value $0.01 per share — | | | |
Authorized — 1,000,000 shares | | | |
Outstanding — 1,000 shares | — |
| | — |
|
Paid-in capital | 3,662 |
| | 3,671 |
|
Retained earnings | 1,478 |
| | 724 |
|
Accumulated other comprehensive income | (2 | ) | | 35 |
|
Total common stockholder's equity | 5,138 |
| | 4,430 |
|
Noncontrolling Interests | 1,360 |
| | 1,245 |
|
Total Stockholders' Equity | 6,498 |
| | 5,675 |
|
Total Liabilities and Stockholders' Equity | $ | 15,206 |
| | $ | 15,169 |
|
Commitments and Contingent Matters (See notes) |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2017, 2016, and 2015
Southern Power Company and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Common Shares Issued | | Common Stock | | Paid-In Capital | | Retained Earnings |
| | Accumulated Other Comprehensive Income | | Total Common Stockholder's Equity | | Noncontrolling Interests(a) | | Total |
| (in millions) |
Balance at December 31, 2014 | — |
| | $ | — |
| | $ | 1,176 |
| | $ | 573 |
| | $ | 3 |
| | $ | 1,752 |
| | $ | 219 |
| | $ | 1,971 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 215 |
| | — |
| | 215 |
| | — |
| | 215 |
|
Capital contributions from parent company | — |
| | — |
| | 646 |
| | — |
| | — |
| | 646 |
| | — |
| | 646 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (131 | ) | | — |
| | (131 | ) | | — |
| | (131 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 567 |
| | 567 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Net loss attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | 12 |
|
Balance at December 31, 2015 | — |
| | — |
| | 1,822 |
| | 657 |
| | 4 |
| | 2,483 |
| | 781 |
| | 3,264 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 338 |
| | — |
| | 338 |
| | — |
| | 338 |
|
Capital contributions from parent company | — |
| | — |
| | 1,850 |
| | — |
| | — |
| | 1,850 |
| | — |
| | 1,850 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 31 |
| | 31 |
| | — |
| | 31 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | (272 | ) | | — |
| | (272 | ) | | — |
| | (272 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 618 |
| | 618 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (57 | ) | | (57 | ) |
Purchase of membership interests from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| | 32 |
|
Other | — |
| | — |
| | (1 | ) | | 1 |
| | — |
| | — |
| | — |
| | — |
|
Balance at December 31, 2016 | — |
| | — |
| | 3,671 |
| | 724 |
| | 35 |
| | 4,430 |
| | 1,245 |
| | 5,675 |
|
Net income attributable to Southern Power | — |
| | — |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
| | — |
| | 1,071 |
|
Capital contributions from parent company | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) | | — |
| | (10 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | (317 | ) | | — |
| | (317 | ) | | — |
| | (317 | ) |
Other comprehensive income transfer from SCS (b) | — |
| | — |
| | — |
| | — |
| | (27 | ) | | (27 | ) | | — |
| | (27 | ) |
Capital contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 79 |
| | 79 |
|
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (122 | ) | | (122 | ) |
Net income attributable to noncontrolling interests | �� |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | 44 |
|
Reclassification from redeemable noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | 114 |
|
Other | — |
| | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) | | — |
| | (7 | ) |
Balance at December 31, 2017 | — |
| | $ | — |
| | $ | 3,662 |
| | $ | 1,478 |
| | $ | (2 | ) | | $ | 5,138 |
| | $ | 1,360 |
| | $ | 6,498 |
|
|
| |
(a) | Excludes redeemable noncontrolling interests. See Note 10 to the financial statements under "Noncontrolling Interests" for additional information. |
(b) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of other comprehensive income, net of tax of $9 million, was transferred from SCS. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Power Company and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Power Company is a wholly-owned subsidiary of Southern Company, which is also the parent company of four traditional electric operating companies, Southern Company Gas (as of July 1, 2016), SCS, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) develop, construct, acquire, own, and manage power generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies.
Effective in December 2017, 538 employees transferred from SCS to the Company. The Company became obligated for related employee costs including pension, other postretirement benefits, and stock-based compensation and has recognized the respective balance sheet assets and liabilities, including AOCI impacts, in its balance sheet at December 31, 2017. Prior to the transfer of employees, the Company's agreements with SCS provided for employee services rendered at amounts in compliance with FERC regulations. The Company adopted the same compensation and benefits plans that SCS has and, therefore, future expenses are not expected to be materially different on a per employee basis.
The preparation of consolidated financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the consolidated financial statements have been reclassified to conform to the current year presentation.
The consolidated financial statements include the accounts of Southern Power Company and its wholly-owned and majority-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing or amounts of revenue recognized in the Company's financial statements. Some contractual arrangements, such as certain capacity and energy payments, are excluded from the scope of ASC 606 and included in the scope of the current leasing guidance or the current derivative guidance.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. The adoption of ASC 606 did not result in a cumulative adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases where the majority relate to land leases for its renewable generation
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
facilities. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet for lessee arrangements.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in other income (expense) in the income statement. Additionally, only the service cost component related to construction labor is eligible for capitalization, when applicable. The Company adopted ASU 2017-07 which is effective for periods beginning after December 15, 2017; however, since the Company became a sponsor of a qualified pension plan and postretirement benefit plan in December 2017, no retrospective presentation of net periodic benefits costs for 2016 or 2017 is required. See Note 2 for additional information.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
Total revenues from all PPAs with affiliates, included in wholesale revenue affiliates on the consolidated statements of income, were $233 million, $258 million, and $219 million for the years ended December 31, 2017, 2016, and 2015, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $81 million for the year ended December 31, 2017 and $109 million for each of the years ended December 31, 2016 and 2015.
The Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Prior to December 2017, the Company did not have employees and thus all employee-related charges were rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS totaled $218 million, $193 million, and $146 million for the years ended December 31, 2017, 2016, and 2015, respectively. Of these costs, $192 million, $173 million, and $138 million for the years ended December 31, 2017, 2016, and 2015, respectively, were charged to other operations and maintenance expenses; the remainder was primarily capitalized to property, plant, and equipment. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
Total power purchased from affiliates through the power pool, included in purchased power in the consolidated statements of income, totaled $27 million for the year ended December 31, 2017 and $21 million for each of the years ended December 31, 2016 and 2015.
The Company also has several agreements with SCS for transmission services. Transmission services purchased from SCS totaled $13 million for the year ended December 31, 2017 and $11 million for each of the years ended December 31, 2016 and 2015 and were charged to other operations and maintenance in the consolidated statements of income. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC.
Prior to Southern Company's acquisition of Southern Company Gas, SCS, as agent for the Company, had agreements with various subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made by the Company from Southern Company Gas' subsidiaries were $119 million for the year ended December 31, 2017 and $17 million for the period subsequent to
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Southern Company's acquisition of Southern Company Gas through December 31, 2016, and are included in fuel expense on the consolidated statements of income.
On September 1, 2016, Southern Company Gas acquired a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG). Prior to completion of the acquisition, SCS, as agent for the Company, had entered into a long-term interstate natural gas transportation agreement with SNG. The interstate transportation service provided to the Company by SNG pursuant to this agreement is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. Transportation costs under this agreement were $25 million for the year ended December 31, 2017 and $7 million for the period subsequent to Southern Company Gas' investment in SNG through December 31, 2016.
The Company and the traditional electric operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. The Company and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity.
Acquisition Accounting
The Company may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, the Company will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the Company includes operating results from the date of acquisition in its consolidated financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition.
The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and the Company may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by the Company for potential or successful acquisitions are expensed as incurred.
Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, the Company fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 8 for additional fair value information.
Revenues
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. All capacity revenues are included in wholesale revenues.
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for additional information.
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. Transmission revenues and other fees are recognized as earned as other operating revenues. See "Financial Instruments" herein for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the Company's top three customers for each of the years presented:
|
| | | | | | | | |
| 2017 | | 2016 | | 2015 |
Georgia Power | 11.3 | % | | 16.5 | % | | 15.8 | % |
Duke Energy Corporation | 6.7 | % | | 7.8 | % | | 8.2 | % |
Morgan Stanley Capital Group | 4.5 | % | | N/A |
| | N/A |
|
San Diego Gas & Electric Company | N/A |
| | 5.7 | % | | N/A |
|
Florida Power & Light Company | N/A |
| | N/A |
| | 10.7 | % |
Fuel Costs
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur.
Development Costs
The Company capitalizes development costs once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as status of power off-take agreements and regulatory approvals, if applicable. Capitalized development costs are included in construction work in progress on the consolidated balance sheets. All development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the consolidated statements of income. If it is determined that a project is no longer probable of completion, any capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences.
Under current tax regulation, certain projects related to the construction of renewable facilities are eligible for federal ITCs. The Company estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. The Company applies the deferred method to ITCs as opposed to the flow-through method. Under the deferred method the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. In addition, certain projects are eligible for federal PTCs, which are recorded as an income tax benefit based on KWH production. Federal ITCs and PTCs available to reduce income taxes payable were not fully utilized during 2017 and will be carried forward and utilized in future years. The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 for additional information.
Property, Plant, and Equipment
The Company's depreciable property, plant, and equipment consists primarily of generation assets.
Property, plant, and equipment is stated at original cost or acquired fair value. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred.
When depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income.
Depreciation
The Company applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain generation assets related to natural gas-fired facilities are depreciated on a units-of-
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets.
The primary assets in property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:
|
| |
Generating facility | Useful life |
Natural gas | Up to 45 years |
Biomass | Up to 40 years |
Solar | Up to 35 years |
Wind | Up to 30 years |
The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term.
Asset Retirement Obligations
Asset retirement obligations (ARO) are computed as the present value of the estimated ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liability primarily relates to the Company's solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. See Note 11 for acquisitions during 2017 and 2016 which contributed to the increased liability.
Details of the AROs included on the consolidated balance sheets are as follows:
|
| | | | | | | | | |
| 2017 | | | 2016 | |
| (in millions) | |
Balance at beginning of year | $ | 64 |
| | | $ | 21 |
| |
Liabilities incurred | 6 |
| | | 42 |
| |
Accretion | 4 |
| | | 1 |
| |
Cash flow revisions | 4 |
| | | — |
| |
Balance at end of year | $ | 78 |
| | | $ | 64 |
| |
Long-Term Service Agreements
The Company has entered into LTSAs for the purpose of securing maintenance support for its natural gas-fired generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in other current assets and noncurrent assets on the consolidated balance sheets and are recorded as payments pursuant to LTSAs and for equipment not yet received in the statements of cash flows. At the time work is performed, which typically occurs during planned inspections, an appropriate amount is transferred from the prepayment to property, plant, and equipment or charged to expense. The receipt of major parts into materials and supplies inventory prior to planned inspections is treated as a noncash transaction for purposes of the consolidated statements of cash flows.
Impairment of Long-Lived Assets and Intangibles
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the PPAs, which have a weighted average term of 19 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded.
Amortization expense for acquired PPAs was $25 million, $10 million, and $3 million for the years ended December 31, 2017, 2016, and 2015, respectively, and is recorded in operating revenues. The estimated annual amortization expense is $25 million for each of the next five years.
Transmission Receivables/Prepayments
As a result of the Company's growth from the acquisition and construction of generating facilities, the Company has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to the Company. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
Restricted Cash
The Company has restricted cash primarily related to certain acquisitions and construction projects. The aggregate amount of restricted cash at December 31, 2017 and 2016 was $11 million and $13 million, respectively.
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Materials and Supplies
Materials and supplies include the average cost of generating plant materials and are recorded as inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.
Fuel Inventory
Fuel inventory, which is included in other current assets, includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several natural gas generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company also maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities on the consolidated balance sheets (included in "Other") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 9 for additional information regarding derivatives.
The Company offsets the fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017 or 2016.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications of amounts included in net income.
Accumulated OCI (loss) balances, net of tax effects, were as follows:
|
| | | | | | | | | |
| Qualifying Hedges | Pension and Other Postretirement Benefit Plans | Accumulated Other Comprehensive Income (Loss) |
| (in millions) |
Balance at December 31, 2016 | $ | 35 |
| $ | — |
| $ | 35 |
|
Current period change | (10 | ) | — |
| (10 | ) |
Other comprehensive income transfer from SCS(*) | — |
| (27 | ) | (27 | ) |
Balance at December 31, 2017 | $ | 25 |
| $ | (27 | ) | $ | (2 | ) |
| |
(*) | In connection with the Company becoming a participant to the Southern Company qualified pension plan and other postretirement benefit plan, $27 million of OCI, net of tax of $9 million, was transferred from SCS. |
Variable Interest Entities
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
2. RETIREMENT BENEFITS
Effective in December 2017, 538 employees transferred from SCS to the Company. Accordingly, the Company assumed various compensation and benefit plans including a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). With the transfer of employees, the Company assumed the related benefit obligations from SCS of $139 million for the qualified pension plan (along with trust assets of $138 million) and $11 million for other postretirement benefit plans, together with $36 million in prior service costs and net gains/losses that are in OCI. In 2018, the Company will also begin providing certain defined benefits under a non-qualified pension plan for a select group of management and highly compensated employees. No obligation related to these benefits was assumed in the employee transfer; however, obligations under the non-qualified pension plan for future services rendered by employees will be recognized beginning in 2018 and ultimately funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans that are to be funded on a cash basis.
Prior to the transfer of employees in December 2017, substantially all expenses charged by SCS, including pension and other postretirement benefit costs, were recorded in other operations and maintenance expense. Beginning in 2018, in connection with the adoption of ASU 2017-07, the service cost component of pension and postretirement benefit costs will be recorded in other operations and maintenance expense while the non-service cost components of pension and postretirement benefit costs will be recorded in other income (expense). See Note 1 under "General" for additional information.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine the benefit obligations for the pension and other postretirement plans as of the December 31, 2017 measurement date are presented below. |
| | |
Assumptions used to determine benefit obligations: | 2017 |
Pension plans | |
Discount rate | 3.94 | % |
Annual salary increase | 4.46 |
|
Other postretirement benefit plans | |
Discount rate | 3.81 | % |
Annual salary increase | 4.46 |
|
In determining the amount of pension cost to be recognized in 2018, the Company estimates the expected rate of return on pension plan assets using a financial model to project the expected return on the current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on the trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), the trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of the trust's portfolio.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) is a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows: |
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.50 | % | | 4.50 | % | | 2026 |
Post-65 medical | 5.00 |
| | 4.50 |
| | 2026 |
Post-65 prescription | 10.00 |
| | 4.50 |
| | 2026 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would have an immaterial effect on the APBO at December 31, 2017.
Pension Plan
The total accumulated benefit obligation for the pension plan was $111 million at December 31, 2017. The projected benefit obligation for the pension plan was $139 million and the fair value of plan assets was $138 million at December 31, 2017.
Presented below are the amounts included in AOCI at December 31, 2017 related to the Company's pension plan that had not yet been recognized in net periodic pension cost, along with the estimated amortization of such amounts for 2018.
|
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Prior service cost | $ | 1 |
| | $ | — |
|
Net (gain) loss | 32 |
| | 2 |
|
AOCI | $ | 33 |
| | |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plan. At December 31, 2017, estimated benefit payments average approximately $4 million each year for the next five years, and for the five-year period from 2023 to 2027 estimated benefit payments are $27 million.
Other Postretirement Benefits
The APBO for the other postretirement benefit plan at December 31, 2017 is $11 million. Amounts recognized in the balance sheet at December 31, 2017 related to the Company's other postretirement benefit plan consist of the following: |
| | | |
| 2017 |
| (in millions) |
Employee benefit obligations (included in other deferred credits and liabilities) | $ | (11 | ) |
AOCI | 3 |
|
Presented below are the amounts included in AOCI at December 31, 2017 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2018. |
| | | | | | | |
| 2017 | | Estimated Amortization in 2018 |
| (in millions) |
Net (gain) loss | $ | 3 |
| | $ | — |
|
AOCI | $ | 3 |
| | |
Future benefit payments, which include any prescription drug benefits, and any offset from drug subsidiary receipts, are immaterial for each of the years 2018-2027.
Benefit Plan Assets
Pension plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for the pension plan cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan assets as of December 31, 2017, along with the targeted mix of assets for the plan, is presented below:
|
| | | | | |
| Target | | 2017 |
Pension plan assets: | | | |
Domestic equity | 26 | % | | 31 | % |
International equity | 25 |
| | 25 |
|
Fixed income | 23 |
| | 24 |
|
Special situations | 3 |
| | 1 |
|
Real estate investments | 14 |
| | 13 |
|
Private equity | 9 |
| | 6 |
|
Total | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Investment Strategies
Detailed below is a description of the investment strategies for each major asset category for the pension benefit plan disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan assets as of December 31, 2017. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The fair values of pension plan assets as of December 31, 2017 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 28 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 41 |
|
International equity(*) | 18 |
| | 16 |
| | — |
| | — |
| | 34 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Corporate bonds | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Pooled funds | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Real estate investments | 5 |
| | — |
| | — |
| | 14 |
| | 19 |
|
Special situations | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Private equity | — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Total | $ | 53 |
| | $ | 61 |
| | $ | — |
| | $ | 24 |
| | $ | 138 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as standards for air, qualitywater, land, and water standards,protection of other natural resources, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
During 2015, the Company indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, the Company is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, the Company is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on the Company's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things,
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. On December 11, 2017, the U.S. District Court for the Western District of Texas dismissed McCarthy's claims against Canadian Solar (USA), Inc. and dismissed cross-claims that XL and North American Elite had sought to bring against Roserock. The Company intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
FERC Matters
The Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional electric operating companies and the Company filed a triennial market power analysis in June 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27,In 2015, the FERC issued an order finding that the traditional electric operating companies' and the Company's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and the Company to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Company filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. FERC in 2015.
In December 2016, the traditional electric operating companies and the Company filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and the Company's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On May 17, 2017, the FERC accepted the traditional electric operating companies' and the Company's compliance filing accepting the terms of the order. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and the Company's June 29, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and the Company to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order or to provide a mitigation plan to further address market power concerns. On November 10, 2017, the traditional electric operating companies and the Company responded to the FERC and proposed to resolve matters by applying the alternative mitigation authorized by the February 2, 2017 order to the adjacent areas made the subject of the October 25, 2017 order.
The ultimate outcome of this matterthese matters cannot be determined at this time.
4. JOINT OWNERSHIP AGREEMENTS
The Company is a 65% owner of Plant Stanton A, a natural gas-fired combined-cycle project unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission (28%), the Florida Municipal Power Agency (3.5%), and the Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2015, $1572017, $155 million was recorded in plant in service with associated accumulated depreciation of $53$55 million. These amounts represent the Company's share of the total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the consolidated statements of income.
5. INCOME TAXES
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined, unitary, or unitary.consolidated. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Southern Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities cannot be determined at this time.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Federal — | | | | | | | | | | |
Current(*) | $ | 12 |
| | $ | 179 |
| | $ | (120 | ) | $ | (566 | ) | | $ | 928 |
| | $ | 12 |
|
Deferred(*) | 10 |
| | (166 | ) | | 159 |
| (312 | ) | | (1,098 | ) | | 10 |
|
| 22 |
| | 13 |
| | 39 |
| (878 | ) | | (170 | ) | | 22 |
|
State — | | | | | | | | | | |
Current | (32 | ) | | (14 | ) | | (5 | ) | (110 | ) | | (60 | ) | | (32 | ) |
Deferred | 31 |
| | (2 | ) | | 12 |
| 49 |
| | 35 |
| | 31 |
|
| (1 | ) | | (16 | ) | | 7 |
| (61 | ) | | (25 | ) | | (1 | ) |
Total | $ | 21 |
| | $ | (3 | ) | | $ | 46 |
| $ | (939 | ) | | $ | (195 | ) | | $ | 21 |
|
| |
(*) | ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized in the current tax year are reclassified from current to deferred taxes in the federal income tax expense above. ITCs and PTCs reclassified in this manner include $316 million for 2017, $1.13 billion for 2016, and $246 million for 20152015. These ITCs and $305 million for 2014. These ITCsPTCs are included in the following table of temporary differences as unrealized tax credits. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Deferred tax liabilities — | | | |
Accelerated depreciation and other property basis differences | $ | 1,364 |
| | $ | 1,006 |
|
Basis difference on asset transfers | 3 |
| | 3 |
|
Levelized capacity revenues | 22 |
| | 17 |
|
Other | 4 |
| | 6 |
|
Total | 1,393 |
| | 1,032 |
|
Deferred tax assets — | | | |
Federal effect of state deferred taxes | 40 |
| | 29 |
|
Net basis difference on federal ITCs | 149 |
| | 102 |
|
Alternative minimum tax carryforward | 15 |
| | 15 |
|
Unrealized tax credits | 551 |
| | 305 |
|
Unrealized loss on interest rate swaps | 4 |
| | 6 |
|
Levelized capacity revenues | 4 |
| | 5 |
|
Deferred state tax assets | 13 |
| | 15 |
|
Other | 18 |
| | 4 |
|
Total | 794 |
| | 481 |
|
Valuation Allowance | (2 | ) | | (8 | ) |
Net deferred income tax assets | 792 |
| | 473 |
|
Accumulated deferred income taxes | $ | 601 |
| | $ | 559 |
|
On November 20, 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. The new guidance resulted in a reclassification from deferred income taxes, current of $306 million and accrued income taxes of $2 million to non-current accumulated deferred income taxes in the Company's December 31, 2014 balance sheet. See Note 1 under "Recently Issued Accounting Standards" for additional information. |
| | | | | | |
| 2017 | 2016 |
| (in millions) |
Deferred tax liabilities — | | |
Accelerated depreciation and other property basis differences | $ | 1,922 |
| $ | 2,440 |
|
Levelized capacity revenues | 26 |
| 28 |
|
Other | 6 |
| 27 |
|
Total deferred income tax liabilities | 1,954 |
| 2,495 |
|
Deferred tax assets — | | |
Federal effect of state deferred taxes | 42 |
| 53 |
|
Basis difference on ITCs | 184 |
| 292 |
|
Alternative minimum tax carryforward | 21 |
| 15 |
|
Unrealized tax credits | 2,002 |
| 1,685 |
|
Federal net operating loss (NOL) | 333 |
| 808 |
|
Deferred state tax assets | 77 |
| 60 |
|
Other partnership basis differences | 24 |
| 16 |
|
Other | 10 |
| 8 |
|
Total deferred income tax assets | 2,693 |
| 2,937 |
|
Valuation Allowance | (13 | ) | — |
|
Net deferred income tax assets | 2,680 |
| 2,937 |
|
Total deferred income tax asset (liability) | $ | 726 |
| $ | 442 |
|
| | |
Recognized in the consolidated balance sheets: | | |
Accumulated deferred income taxes – assets | $ | 925 |
| $ | 594 |
|
Accumulated deferred income taxes – liability | $ | (199 | ) | $ | (152 | ) |
Deferred tax liabilities are primarily the result of property relatedproperty-related timing differences. The applicationdifferences, which increased due to bonus depreciation. However, the implementation of bonus depreciation provisions in current tax law hasthe Tax Reform Legislation significantly increasedreduced the amount of accumulated deferred tax liabilities related to accelerated depreciation in 2015 and 2014.income taxes at December 31, 2017.
Deferred tax assets consist primarily of timing differences related to the carryforward of unrealized federal ITCs, PTCs, net operating loss, and net basis differences on federal ITCsITCs.
Tax Credit Carryforwards
At December 31, 2017, the Company had federal ITC and the carryforwardPTC carryforwards, which are expected to result in $2.0 billion of unrealized federal ITCs.income tax benefits. The federal ITC carryforwards begin expiring in 2034 but are expected to be fully utilized by 2020.2027. The PTC carryforwards begin expiring in 2036 but are also expected to be fully utilized by 2027. The acquisition of additional renewable projects could further delay the utilization of existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.
At December 31, 2015 and December 31, 2014,Net Operating Loss
After carrying back portions of the federal NOL generated in 2016, Southern Company had state net operating loss (NOL) carryforwardsa consolidated federal NOL carryforward of $225 million and $247 million, respectively. The NOL carryforwards resulted in deferred tax assets of $8 million as of December 31, 2015 and $9 million as of December 31, 2014. The Company has established a valuation allowance due to the remote likelihood that the full tax benefits will be realized. During 2015, approximately $87 million in NOLs expired resulting in a decrease in the valuation allowance for the same amount. The offsetting adjustments resulted in no tax impact. Of the NOL balance$2.3 billion at December 31, 2015, approximately $40 million2017. The federal NOL will expire in 2017 and $185 million will expire from 20332037 but is expected to 2035.be fully utilized by 2019. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
The Company had state NOL carryforwards of approximately $1.3 billion at December 31, 2017, which will expire from 2029 to 2035. These carryforwards resulted in deferred tax assets of approximately $61 million as of December 31, 2017. The state NOL carryforwards by state jurisdiction were as follows:
|
| | | | | | | |
Jurisdiction | Approximate NOL Carryforwards | Approximate Net State Income Tax Benefit | Tax Year NOL Expires |
| (in millions) | |
Oklahoma | $ | 978 |
| $ | 46 |
| 2035 |
Florida | 283 |
| 12 |
| 2033 |
South Carolina | 48 |
| 2 |
| 2035 |
Other states | 23 |
| 1 |
| 2029-2035 |
Balance at year end | $ | 1,332 |
| $ | 61 |
| |
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | 35.0 | % | | 35.0 | % | | 35.0 | % |
State income tax, net of federal deduction | (0.3 | ) | | (6.0 | ) | | 2.2 |
| (22.2 | ) | | (9.1 | ) | | (0.3 | ) |
Amortization of ITC | (5.0 | ) | | (4.3 | ) | | (1.7 | ) | (31.8 | ) | | (20.6 | ) | | (5.0 | ) |
ITC basis difference | (21.5 | ) | | (27.7 | ) | | (14.5 | ) | (10.0 | ) | | (89.0 | ) | | (21.5 | ) |
Production tax credits | | (72.5 | ) | | (23.3 | ) | | (0.6 | ) |
Tax Reform Legislation | | (416.1 | ) | | — |
| | — |
|
Noncontrolling interests | | (8.6 | ) | | (6.2 | ) | | (1.7 | ) |
Other | 0.2 |
| | 1.1 |
| | 0.3 |
| 0.5 |
| | 4.6 |
| | 2.5 |
|
Effective income tax rate | 8.4 | % | | (1.9 | )% | | 21.3 | % | |
Effective income tax rate (benefit) | | (525.7 | )% | | (108.6 | )% | | 8.4 | % |
The Company's effective tax rate increased in 2015 primarily due to decreased benefits from federal ITCs as compared to 2014. The Company's effective tax rate decreased in 20142017 primarily due to greater benefits fromthe Tax Reform Legislation. The decrease in 2016 was primarily due to changes in federal ITCs as comparedand PTCs.
The Company's deferred federal ITCs are amortized to 2013.
Theincome tax expense over the life of the respective asset. ITCs amortized in this manner amounted to $57 million in 2017, $37 million in 2016, and $19 million in 2015. Also, the Company received cash related to federal ITCs under the renewable energy initiativesincentives of $162 million for the year ended December 31, 2015. While no cash was received related to these incentives in 2017 or 2016, the Company recognized tax credits. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year 2015, $74 million in tax year 2014, and $158 million in tax year 2013.which the plant reaches commercial operation. The tax benefit of the related basis differencedifferences reduced income tax expense by $18 million in 2017, $173 million in 2016, and $54 million in 2015, $48 million in 2014, and $31 million in 2013. Federal ITCs amortized to2015. The tax benefit of PTCs reduced income tax expense amountedby $129 million in 2017, $42 million in 2016 and $1 million in 2015. See "Unrecognized Tax Benefits" herein for further information.
Legal Entity Reorganization
In September 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of the solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization included the purchase of all of the redeemable noncontrolling interests, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC. The reorganization is expected to $19 million, $11be substantially completed in the first quarter 2018 and is expected to result in estimated tax benefits totaling between $50 million and $6$55 million related to certain changes in 2015, 2014,state apportionment rates and 2013, respectively.net operating loss carryforward utilization that will be recorded in the first quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
See Note 1 under "Income
NOTES (continued)
Southern Power Company and Other Taxes" for additional information.Subsidiary Companies 2017 Annual Report
Unrecognized Tax Benefits
Changes during the year in unrecognized tax benefits were as follows:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| (in millions) | (in millions) |
Unrecognized tax benefits at beginning of year | $ | 5 |
| | $ | 2 |
| | $ | 3 |
| |
Balance at beginning of year | | $ | 17 |
| | $ | 8 |
| | $ | 5 |
|
Tax positions increase from current periods | 9 |
| | 5 |
| | 2 |
| — |
| | 17 |
| | 9 |
|
Tax positions decrease from prior periods | (6 | ) | | (2 | ) | | (3 | ) | (17 | ) | | (8 | ) | | (6 | ) |
Balance at end of year | $ | 8 |
| | $ | 5 |
| | $ | 2 |
| $ | — |
| | $ | 17 |
| | $ | 8 |
|
The increase in unrecognized tax benefits from current periods for 2015, 2014 and 2013,all years presented, and the decrease from prior periods in 2015 and 2014for all years presented, primarily relate to federal income tax benefits from deferred ITCs and would eachall impact the Company's effective tax rate, if recognized. The decrease in unrecognizedimpact on the effective tax benefits from prior periods for 2013 relates torate is determined based on the Company's compliance with final U.S. Treasury regulations for the tax method change for repairs.amount of ITCs which are uncertain.
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
6. FINANCING
Southern Power Company's senior notes, bank term loans, commercial paper, and credit facility Facility (as defined herein) are unsecured senior debt securities,indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company.Company. The Company's subsidiaries are not issuers, borrowers, or obligors, as applicable, under the senior notes, borrowings from financial institutions, commercial paper, or the Facility. The senior notes, borrowings from financial institutions, commercial paper, and credit facilitythe Facility are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of Southern Powerthe Company's subsidiaries. As of December 31, 20152017, the companyCompany had no secured debt at its subsidiaries other than.
Securities Due Within One Year
At December 31, 2017, the three secured project credit facilities,Company had $420 million in term loans and $350 million of senior notes due within one year. At December 31, 2016, the Company had a $60 million term loan, $500 million of senior notes, and $1 million of long-term notes due within one year.
Maturities of long-term debt for the next five years are as follows:
|
| | | |
| December 31, 2017 |
| (in millions) |
2018 | $ | 770 |
|
2019 | 600 |
|
2020 | 825 |
|
2021 | 300 |
|
2022(*) | 677 |
|
| |
(*) | Represents euro-denominated debt at the U.S. dollar denominated hedge settlement amount. |
Senior Notes
In November 2017, the Company issued $525 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due December 20, 2020, which are discussed below.bear interest based on three-month LIBOR. The net proceeds were used to redeem all of the $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017 and to repay a portion of the Company's outstanding short-term debt.
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
Securities Due Within One Year
At December 31, 20152017 and 2014,2016, the Company had a $400 million bank loan$5.5 billion and $525 million$5.3 billion of senior notes outstanding, respectively, which included senior notes due within one year, respectively. In addition, at December 31, 2015, the Company classified as due within one year approximately $3 million of long-term notes payable to TRE that are expected to be repaid in 2016.year.
Maturities through 2020 applicable to total long-term debt are as follows: $500 million in 2017, $350 million in 2018, and $300 million in 2020.
Other Long-Term Notes
During 2015,In September 2017, the Company prepaid $4 million of long-term notes payable to TRE and issued $2 million due September 30, 2035 under a promissory note related to the financing of Morelos. At December 31, 2015 and 2014, the Company had $13 million and $19 million, respectively, of long-term notes payable to TRE.
In August 2015, the Company entered into a $400amended its $60 million aggregate principal amount 13-month floating rate bankterm loan bearing interest based on one-month LIBOR.to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes, including the Company's growth strategy and continuous construction program.purposes.
This bank loan hasAt December 31, 2017, outstanding term loans were included in securities due within one year.
The outstanding term loans as of December 31, 2017 have a covenant that limits debt levels to 65% of total capitalization, as defined in the agreement.agreements. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Companycompany to the extent such debt is non-recourse to the Company,company, and capitalization excludes the capital stock or other equity attributable to such subsidiary.
At December 31, 2015,2017, the Company was in compliance with its debt limits.
Senior Notes
In May 2015, the Company issued $350 million aggregate principal amount of its Series 2015A 1.500% Senior Notes due June 1, 2018 and $300 million aggregate principal amount of Series 2015B 2.375% Senior Notes due June 1, 2020. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, including the Company’s growth strategy and continuous construction program, and for a portion of the repayment at maturity of $525 million aggregate principal amount of the Company's 4.875% Senior Notes on July 15, 2015.
In November 2015, the Company issued $500 million aggregate principal amount of its Series 2015C 4.15% Senior Notes due December 1, 2025 and $500 million aggregate principal amount of Series 2015D 1.85% Senior Notes due December 1, 2017. The proceeds will be used for renewable energy generation projects.
At December 31, 2015 and 2014, the Company had $2.7 billion and $1.6 billion of senior notes outstanding, respectively, which included senior notes due within one year.
Bank Credit Arrangements
Company FacilityCredit Facilities
At December 31, 2017, the Company had a committed credit facility (Facility) of $750 million expiring in 2022, of which $22 million has been used for letters of credit and $728 million remains unused. In August 2015,May 2017, the Company amended and restated its multi-year credit facility (Facility). This amendment extendedthe Facility, which, among other things, extended the maturity date from 20182020 to 2020. The Company also2022 and increased itsthe Company's borrowing ability under the Facility to $600$750 million from $500$600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. As of December 31, 2015, the total amount available under the Facility2016, $78 million was $566 million. As of December 31, 2014, the total amount available under the previous $500 million facility was $488 million. The amounts outstanding as of December 31, 2015 and 2014 reflect $34 million and $12 million inused for letters of credit respectively.and $522 million remained unused. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, the Company plansexpects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, the Company may extend the maturity date and/or increase or decrease the lending commitment thereunder. The Company's subsidiaries are not parties to the Facility.
The Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/4 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of the Company to the extent such debt is non-recourse to the Company, and capitalization excludes the capital stock or other equity attributable to such subsidiary. At December 31, 2015,2017, the Company was in compliance with its debt limits.
Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program.
NOTES (continued)
Southern PowerThe Company and Subsidiary Companies 2015 Annual Report
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of the Company, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a)also has a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured$120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At December 31, 2017, $101 million has been used for letters of credit, primarily as credit support for PPA requirements, and is secured by$19 million remains unused. At December 31, 2016, the membership intereststotal amount available under this facility was $82 million. The Company's subsidiaries are not parties to this letter of project companies. Proceeds fromcredit facility.
In addition, at both December 31, 2017 and 2016, the Project Credit Facilities are being used to finance project costsCompany has $113 million of cash collateral posted related to the solar facility currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of December 31, 2015.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total | | Total Undrawn | | Letter of Credit Facility | | Total Undrawn |
| | | | (in millions) |
Tranquillity | | Earlier of COD or December 31, 2016 | | $ | 86 |
| | $ | 172 |
| | $ | 258 |
| | $ | 147 |
| | $ | 77 |
| | $ | 26 |
|
Roserock | | Earlier of COD or November 30, 2016 | | 63 |
| | 180 |
| | 243 |
| | 243 |
| | 23 |
| | 23 |
|
Garland | | Earlier of COD or November 30, 2016 | | 86 |
| | 308 |
| | 394 |
| | 368 |
| | 49 |
| | 32 |
|
Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 758 |
| | $ | 149 |
| | $ | 81 |
|
The total amount outstanding on the Project Credit Facilities as of December 31, 2015 was $137 million at a weighted average interest rate of 2.0% andPPA requirements, which is included in notes payableother deferred charges and assets in the consolidated balance sheet.
The Company expects to repay these Project Credit Facilities from its traditional sources of capital upon their maturity.sheets.
Commercial Paper Program
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. The Company's subsidiaries are not parties to the commercial paper program. Commercial paper is included in notes payable in the consolidated balance sheets as noted below:
|
| | | | | | |
| Commercial Paper at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2015 | $ | — |
| | N/A |
|
December 31, 2014 | $ | 195 |
| | 0.4 | % |
|
| | | | | | |
| Commercial Paper at the End of the Period |
| Amount Outstanding | | Weighted Average Interest Rate |
| (in millions) | | |
December 31, 2017 | $ | 105 |
| | 2.0 | % |
December 31, 2016 | $ | — |
| | N/A |
|
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Subsidiary Project Credit Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Garland Holdings LLC, and RE Roserock LLC, indirect subsidiaries of the Company, each subsidiary had entered into separate credit agreements (Project Credit Facilities), which were non-recourse to the Company (other than the subsidiary party to the agreement). Each Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that was secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility was secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The Tranquillity and Garland Project Credit Facilities were fully repaid on October 14, 2016 and December 29, 2016, respectively. The table below summarizes the Roserock Project Credit Facility as of December 31, 2016, which was extended to January 31, 2017 and fully repaid on January 17, 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | (in millions) |
December 31, 2016 | | | $ | 63 |
| | $ | 180 |
| | $ | 243 |
| | $ | 34 |
| | $ | 23 |
| | $ | 16 |
|
The Project Credit Facilities had no amount outstanding at December 31, 2017 and $209 million outstanding with a weighted average interest rate of 2.1% as of December 31, 2016.
Assets Subject to Lien
Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. See Note 11 for additional information.
Roserock is in a litigation dispute with McCarthy regarding damage to certain solar panels during installation. In connection therewith, Roserock is withholding payments of approximately $26 million from McCarthy, and McCarthy has filed mechanic's liens on the Roserock facility for the same amount. See Note 3 for additional information.
Dividend Restrictions
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
7. COMMITMENTS
Fuel Agreements
SCS, as agent for the Company and the traditional electric operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities whichCompany's generating facilities. These purchase obligations are not recognized on the Company's consolidated balance sheets. In 2015, 2014, and 2013, theThe Company incurred fuel expense of $621 million, $456 million, and $441 million $596 million,for the years ended December 31, 2017, 2016, and $474 million,2015, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and Southern Company's traditional electric operating companies. Under these agreements, each of the traditional electric operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional electric operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Operating Leases
The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $29 million, $22 million, and $7 million $4 million,for the years ended December 31, 2017, 2016, and $2 million for 2015, 2014, and 2013, respectively. These amounts include contingent rent expense related to a land leaseleases based on wind production and escalation in the Consumer Price Index for All Urban Consumers. The Company excludes contingent rent but includes step rents, fixed escalations, lease concessions, and lease extensions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. As of December 31, 2015,2017, estimated minimum lease payments under operating leases were $11$22 million in 2016, $12each of 2018, 2019, and 2020, $23 million in 2017, $12each of 2021 and 2022, and $815 million in 2018, $12 million in 2019, $13 million in 2020, and $595 million in 20212023 and thereafter. The majority of the committed future expenditures are related to land leases for solar and wind facilities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Redeemable Noncontrolling Interests
TRE can require the Company to purchase its redeemable noncontrolling interests in STR, which owns various solar facilities contracted under long-term PPAs, at fair market value pursuant to the partnership agreement. As of December 31, 2015, the redeemable noncontrolling interests were $43 million.
See Note 10 for additional information.10.
8. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
Level 1 consists of observable market data in an active market for identical assets or liabilities.
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
As of December 31, 20152017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2015: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2017: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
| $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
|
Interest rate derivatives | — |
| | 3 |
| | — |
| | 3 |
| |
Foreign currency derivatives | | — |
| | 129 |
| | — |
| | 129 |
|
Cash equivalents | 511 |
| | — |
| | — |
| | 511 |
| 21 |
| | — |
| | — |
| | 21 |
|
Total | $ | 511 |
| | $ | 7 |
| | $ | — |
| | $ | 518 |
| $ | 21 |
| | $ | 132 |
| | $ | — |
| | $ | 153 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 13 |
| | $ | — |
| | $ | 13 |
|
Foreign currency derivatives | | — |
| | 23 |
| | — |
| | 23 |
|
Contingent consideration | | — |
| | — |
| | 22 |
| | 22 |
|
Total | | $ | — |
| | $ | 36 |
| | $ | 22 |
| | $ | 58 |
|
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
As of December 31, 20142016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | |
As of December 31, 2014: | (Level 1) | | (Level 2) | | (Level 3) | | Total | |
As of December 31, 2016: | | (Level 1) | | (Level 2) | | (Level 3) | | Total |
| (in millions) | (in millions) |
Assets: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
| $ | — |
| | $ | 21 |
| | $ | — |
| | $ | 21 |
|
Interest rate derivatives | | — |
| | 1 |
| | — |
| | 1 |
|
Cash equivalents | 18 |
| | — |
| | — |
| | 18 |
| 628 |
| | — |
| | — |
| | 628 |
|
Total | $ | 18 |
| | $ | 5 |
| | $ | — |
| | $ | 23 |
| $ | 628 |
| | $ | 22 |
| | $ | — |
| | $ | 650 |
|
Liabilities: | | | | | | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
| $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
|
Foreign currency derivatives | | — |
| | 58 |
| | — |
| | 58 |
|
Contingent consideration | | — |
| | — |
| | 18 |
| | 18 |
|
Total | | $ | — |
| | $ | 63 |
| | $ | 18 |
| | $ | 81 |
|
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflectreflects the net present value of expected payments and receipts under the swap agreement based on the market’smarket's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 9 for additional information on how these derivatives are used.
The Company has contingent payment obligations related to certain acquisitions whereby the Company is primarily obligated to make generation-based payments to the seller commencing at the commercial operation date through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
As of December 31, 20152017 and 20142016, other financial instruments for which the carrying amount did not equal fair value were as follows:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2015 | $ | 3,122 |
| | $ | 3,117 |
|
2014 | $ | 1,610 |
| | $ | 1,785 |
|
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 5,841 |
| | $ | 6,079 |
|
2016 | $ | 5,628 |
| | $ | 5,691 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.
9. DERIVATIVES
The Company is exposed to market risks, primarily commodity price risk and interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the consolidated balance sheets as either assets or liabilities and are presented on a grossnet basis. See Note 8 for additional fair value information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. The Company has limited exposure to market volatility in energy-related commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity.
Energy-related derivative contracts are accounted for under one of two methods:
Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the consolidated statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 20152017, the net volume of energy-related derivative contracts for natural gas positions totaled 1014 million mmBtu, all of which expire by 2017, which is the longest non-hedge date.in 2018. At December 31, 2015,2017, the net volume of energy-related derivative contracts for power positions was immaterial.3 million MWHs, all of which expire in 2018.
In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 110 million mmBtu.
For cash flow hedges, the amountsgains (losses) expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 20162018 is immaterial.$(7) million.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Interest Rate Derivatives
The Company may also enter into interest rate derivatives from time to time to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
At December 31, 2015,2017, the followingCompany did not have any interest rate derivatives were outstanding:
|
| | | | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value Gain (Loss) December 31, 2015 |
| (in millions) | | | | | | | | (in millions) |
Derivatives not Designated as Hedges | | | | | | | | |
| $ | 65 |
| (a,d) | 3-month LIBOR | | 2.50% | | October 2016 | (e) | $ | 1 |
|
| 47 |
| (b.d) | 3-month LIBOR | | 2.21% | | October 2016 | (e) | 1 |
|
| 65 |
| (c,d) | 3-month LIBOR | | 2.21% | | November 2016 | (f) | 1 |
|
Total | $ | 177 |
| | | | | | | | $ | 3 |
|
| |
(a) | Swaption at RE Tranquillity LLC. See Note 2 for additional information. |
| |
(b) | Swaption at RE Roserock LLC. See Note 2 for additional information. |
| |
(c) | Swaption at RE Garland Holdings LLC. See Note 2 for additional information. |
| |
(d) | Amortizing notional amount. |
| |
(e) | Represents the mandatory settlement date. Settlement amount will be based on a 15-year amortizing swap. |
| |
(f) | Represents the mandatory settlement date. Settlement amount will be based on a 12-year amortizing swap. |
The Company hasoutstanding and does not have any deferred gains and losses in AOCI related to past cash flow hedges that are expected to be amortized into earnings through 2016. The estimated pre-tax loss that willwould be reclassified from AOCI to interest expenseexpense.
Foreign Currency Derivatives
The Company may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
At December 31, 2017, the following foreign currency derivatives were outstanding: |
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
| $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | 55 |
|
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 51 |
|
Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | 106 |
|
The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2016 is immaterial.2018 total $(23) million.
Derivative Financial Statement Presentation and Amounts
At December 31, 2015 and 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | | | | | | |
| Asset Derivatives | | Liability Derivatives |
Derivative Category | Balance Sheet Location | 2015 | | 2014 | | Balance Sheet Location | 2015 | | 2014 |
| | (in millions) | | | (in millions) |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | |
Energy-related derivatives: | Assets from risk management activities | $ | 3 |
| | $ | — |
| | Other current liabilities | $ | 2 |
| | $ | — |
|
Derivatives not designated as hedging instruments | | | | | | | | | |
Energy-related derivatives: | Assets from risk management activities | $ | 1 |
| | $ | 5 |
| | Other current liabilities | $ | 1 |
| | $ | 4 |
|
Interest rate derivatives: | Assets from risk management activities | 3 |
| | — |
| | Other current liabilities | — |
| | — |
|
Total derivatives not designated as hedging instruments | | $ | 4 |
| | $ | 5 |
| | | $ | 1 |
| | $ | 4 |
|
Total | | $ | 7 |
| | $ | 5 |
| | | $ | 3 |
| | $ | 4 |
|
NOTES (continued)
Southern PowerThe Company and Subsidiary Companies 2015 Annual Report
The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of theseenters into energy-related and interest rate derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts relatedFair value amounts of derivative assets and liabilities on the consolidated balance sheets are presented net to energy-related derivative contracts atthe extent that there are netting arrangements or similar agreements with counterparties.
At December 31, 20152017 and 2014 are presented2016, the fair value of energy-related, interest rate, and foreign currency derivatives reflected in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offsetconsolidated balance sheets is as follows:
NOTES (continued)
Southern Power Company and are therefore excluded from the offsetting disclosure tables below.Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | |
Fair Value |
Assets | 2015 |
| | 2014 |
| | Liabilities | 2015 |
| | 2014 |
|
| (in millions) | | | (in millions) |
Energy-related derivatives presented in the Balance Sheet (a) | $ | 4 |
| | $ | 5 |
| | Energy-related derivatives presented in the Balance Sheet (a) | $ | 3 |
| | $ | 4 |
|
Gross amounts not offset in the Balance Sheet (b) | (1 | ) | | — |
| | Gross amounts not offset in the Balance Sheet (b) | (1 | ) | | — |
|
Net energy-related derivative assets | $ | 3 |
| | $ | 5 |
| | Net energy-related derivative liabilities | $ | 2 |
| | $ | 4 |
|
|
| | | | | | | | | | | | | |
| 2017 | | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | | Assets | Liabilities |
| (in millions) |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 11 |
| | $ | 18 |
| $ | 4 |
|
Foreign currency derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| 23 |
| | — |
| 25 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 129 |
| — |
| | — |
| 33 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 132 |
| $ | 34 |
| | $ | 18 |
| $ | 62 |
|
Derivatives not designated as hedging instruments | | | | | |
Energy-related derivatives: | | | | | |
Other current assets/Other current liabilities | $ | — |
| $ | 2 |
| | $ | 3 |
| $ | 1 |
|
Interest rate derivatives: | | | | | |
Other current assets/Other current liabilities | — |
| — |
| | 1 |
| — |
|
Total derivatives not designated as hedging instruments | $ | — |
| $ | 2 |
| | $ | 4 |
| $ | 1 |
|
Gross amounts of recognized assets and liabilities | $ | 132 |
| $ | 36 |
| | $ | 22 |
| $ | 63 |
|
Gross amounts offset | $ | (3 | ) | $ | (3 | ) | | $ | (5 | ) | $ | (5 | ) |
Net amounts of assets and liabilities | $ | 129 |
| $ | 33 |
| | $ | 17 |
| $ | 58 |
|
| |
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
For the years ended December 31, 2015, 2014,2017, 2016, and 2013,2015, the pre-tax effects of energy-related, interest rate, and foreign currency derivatives designated as cash flow hedging instruments on the consolidated statements of income were as follows:
|
| | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Reclassified from AOCI into Income (Effective Portion) |
| Amount |
Derivative Category | Statements of Income Location | 2015 |
| | 2014 |
| | 2013 |
| | (in millions) |
Interest rate derivatives | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | | $ | (6 | ) |
For the years ended December 31, 2015, 2014, and 2013, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and reclassified from AOCI into earnings were immaterial. |
| | | | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from AOCI into Income (Effective Portion) |
Derivative Category | 2017 | 2016 | 2015 | | Statements of Income Location | 2017 | 2016 | 2015 |
| (in millions) | | | (in millions) |
Energy-related derivatives | $ | (38 | ) | $ | 14 |
| $ | — |
| | Amortization | $ | (17 | ) | $ | 2 |
| $ | — |
|
Interest rate derivatives | — |
| — |
| — |
| | Interest expense, net of amounts capitalized | — |
| (1 | ) | (1 | ) |
Foreign currency derivatives | 140 |
| (58 | ) | — |
| | Interest expense, net of amounts capitalized | (23 | ) | (13 | ) | — |
|
| | | | | Other income (expense), net | 159 |
| (82 | ) | — |
|
Total | $ | 102 |
| $ | (44 | ) | $ | — |
| | | $ | 119 |
| $ | (94 | ) | $ | (1 | ) |
There was no material ineffectiveness recorded in earnings for any period presented.
The pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the Company's consolidated statements of income were not material for any year presented.
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2015, the amount of2017, there was no collateral posted with itsthe Company's derivative counterparties was immaterial.counterparties.
At December 31, 2015,2017, the fair value of derivative liabilities with contingent features was immaterial.$8 million. However, becausethe fair value of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-relatedderivative liabilities with contingent features, at a rating below BBB- and/or Baa3, were $52 million, and includeincluding certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade.grade because of joint and several liability features underlying these derivatives, was $12 million at December 31, 2017.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company maintains accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, the Company may be required to post collateral. At December 31, 2017, cash collateral posted was immaterial.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the
NOTES (continued)
Southern Power Company and Subsidiary Companies 2015 Annual Report
Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
10. NONCONTROLLING INTERESTS
In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to non-redeemable noncontrolling interests due to the expiration of an option allowing SunPower Corporation to require the Company to purchase its redeemable noncontrolling interest at fair market value. In addition, Turner Renewable Energy, LLC owned a 10% redeemable noncontrolling interest in certain of the Company's solar facilities. These noncontrolling interests were redeemed in October 2017 at fair market value pursuant to the partnership agreement. As of December 31, 2017, there were no outstanding redeemable noncontrolling interests.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The following table detailspresents the components ofchanges in redeemable noncontrolling interests for the years ended December 31:
| | | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | | (in millions) | | | | | (in millions) | | |
Beginning balance | $ | 39 |
| | $ | 29 |
| | $ | 8 |
| $ | 164 |
| | $ | 43 |
| | $ | 39 |
|
Net income attributable to redeemable noncontrolling interests | 2 |
| | 4 |
| | 4 |
| 2 |
| | 4 |
| | 2 |
|
Distributions to redeemable noncontrolling interests | — |
| | (1 | ) | | — |
| (2 | ) | | (1 | ) | | — |
|
Capital contributions from redeemable noncontrolling interests | 2 |
| | 7 |
| | 17 |
| 2 |
| | 118 |
| | 2 |
|
Redemption of redeemable noncontrolling interests | | (59 | ) | | — |
| | — |
|
Reclassification to non-redeemable noncontrolling interests | | (114 | ) | | — |
| | — |
|
Change in fair value of redeemable noncontrolling interests | | 7 |
| | — |
| | — |
|
Ending balance | $ | 43 |
| | $ | 39 |
| | $ | 29 |
| $ | — |
| | $ | 164 |
| | $ | 43 |
|
ForThe following table presents the attribution of net income to the Company and the noncontrolling interests for the years ended December 31:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (in millions) |
Net income | $ | 1,117 |
| | $ | 374 |
| | $ | 229 |
|
Less: Net income attributable to noncontrolling interests | 44 |
| | 32 |
| | 12 |
|
Less: Net income attributable to redeemable noncontrolling interests | 2 |
| | 4 |
| | 2 |
|
Net income attributable to the Company | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
|
11. ACQUISITIONS
During 2017 and 2016, in accordance with its overall growth strategy, the Company or one of its wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below. Also, in March 2016, the Company acquired an additional 15% interest in Desert Stateline, 51% of which was initially acquired in 2015. As a result, the Company and the class B member are now entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, the Company will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Acquisition-related costs were expensed as incurred and were not material for any of the years presented.
The following table presents the Company's acquisition activity for the year ended, and subsequent to, December 31, 20152017.
|
| | | | | | | | | | |
Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual / Expected COD | PPA Contract Period |
Business Acquisitions During the Year Ended December 31, 2017 |
Bethel | Wind | Invenergy Wind Global LLC, January 6, 2017 | 276 | | Castro County, TX | 100 | % | | January 2017 | 12 years |
Cactus Flats(a) | Wind | RES America Developments, Inc., July 31, 2017 | 148 | | Concho County, TX | 100 | % | | Third quarter 2018 | 12 years and 15 years |
Asset Acquisitions Subsequent to December 31, 2017 |
Gaskell West 1 | Solar | Recurrent Energy Development Holdings, LLC, January 26, 2018 | 20 | | Kern County, CA | 100% of Class B |
| (b) | March 2018 | 20 years |
| |
(a) | On July 31, 2017, the Company purchased 100% of the Cactus Flats facility and commenced construction. Upon placing the facility in service, the Company expects to close on a tax equity partnership agreement that has already been executed, subject to various customary conditions at closing, and will then own 100% of the class B membership interests. |
| |
(b) | The Company owns 100% of the class B membership interest under a tax equity partnership agreement. |
NOTES (continued)
Southern Power Company and 2014,Subsidiary Companies 2017 Annual Report
Business Acquisitions During the Year Ended December 31, 2017
The Company's aggregate purchase price for acquisitions during the year ended December 31, 2017 was $539 million. The fair values of the assets acquired and liabilities assumed were finalized in 2017 and recorded as follows:
|
| | | |
| 2017 |
| (in millions) |
Restricted cash | $ | 16 |
|
CWIP | 534 |
|
Other assets | 5 |
|
Accounts payable | (16 | ) |
Total purchase price | $ | 539 |
|
In 2017, total revenues of $15 million and net income included in the consolidated statements of changes in stockholders' equity is reconciled to net income presented$17 million, primarily as a result of PTCs, was recognized in the consolidated statements of income by the Company related to the 2017 acquisitions. The Bethel facility did not have operating revenues or activities prior to completion of construction and being placed in service, and the Cactus Flats facility is still under construction. Therefore, supplemental pro forma information as follows:though the acquisitions occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.
Construction Projects in Progress |
| | | | | | | |
| 2015 | | 2014 |
| (in millions) |
Net income attributable to the Company | $ | 215 |
| | $ | 172 |
|
Net income (loss) attributable to noncontrolling interests | 12 |
| | (1 | ) |
Net income attributable to redeemable noncontrolling interests | 2 |
| | 4 |
|
Net income | $ | 229 |
| | $ | 175 |
|
ForDuring the year ended December 31, 2013, net income attributable2017, in accordance with its overall growth strategy, the Company continued construction on the 345-MW Mankato expansion project and commenced construction on the Cactus Flats facility. Total aggregate construction costs for these facilities, excluding acquisition costs and including construction costs to redeemable noncontrolling interests was $4complete the subsequently-acquired Gaskell West 1 solar project, are expected to be between $385 million and was$430 million. At December 31, 2017, construction costs included in "Other income (expense), net"CWIP related to these projects totaled $188 million. The ultimate outcome of these matters cannot be determined at this time.
Development Projects
During 2017, as part of the Company's renewable development strategy, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects, up to 900 MWs in total. Once these wind projects reach commercial operations, which is expected in 2021, they are expected to qualify for 80% PTCs.
During 2016, the consolidated statementsCompany entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of income.wind projects expected to be placed in service between 2018 and 2020. In addition, in 2016, the Company purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Once these wind projects reach commercial operations, they are expected to qualify for 100% PTCs.
The ultimate outcome of these matters cannot be determined at this time.
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
The following table presents the Company's acquisitions for the year ended December 31, 2016.
|
| | | | | | | | | | |
Project Facility | Resource | Seller, Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Ownership Percentage | Actual COD | PPA Contract Period |
Acquisitions for the Year Ended December 31, 2016 |
Boulder 1 | Solar | SunPower Corporation, November 16, 2016 | 100 | | Clark County, NV | 51 | % | (a) | December 2016 | 20 years |
Calipatria | Solar | Solar Frontier Americas Holding LLC, February 11, 2016 | 20 | | Imperial County, CA | 100 | % | (b) | February 2016 | 20 years |
East Pecos | Solar | First Solar, Inc., March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | March 2017 | 15 years |
Grant Plains | Wind | Apex Clean Energy Holdings, LLC, August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | 20 years and 12 years (c) |
Grant Wind | Wind | Apex Clean Energy Holdings, LLC, April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | 20 years |
Henrietta | Solar | SunPower Corporation, July 1, 2016 | 102 | | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
Lamesa | Solar | RES America Developments Inc., July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | April 2017 | 15 years |
Mankato (d) | Natural Gas | Calpine Corporation, October 26, 2016 | 375 | | Mankato, MN | 100 | % | | N/A (e) | 10 years |
Passadumkeag | Wind | Quantum Utility Generation, LLC, June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
Rutherford | Solar | Cypress Creek Renewables, LLC, July 1, 2016 | 74 | | Rutherford County, NC | 100 | % | (b) | December 2016 | 15 years |
Salt Fork | Wind | EDF Renewable Energy, Inc., December 1, 2016 | 174 | | Donley and Gray Counties, TX | 100 | % | | December 2016 | 14 years and 12 years |
Tyler Bluff | Wind | EDF Renewable Energy, Inc., December 21, 2016 | 125 | | Cooke County, TX | 100 | % | | December 2016 | 12 years |
Wake Wind | Wind | Invenergy Wind Global LLC, October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | (f) | October 2016 | 12 years |
| |
(a) | The Company owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. The Company and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to the transaction. |
| |
(b) | The Company originally purchased 90%, with a minority owner owning 10%. During 2017, the Company acquired the remaining 10% ownership interest. See Note 10 for additional information. |
| |
(c) | In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
(d) | Under the terms of the PPA and the expansion PPA, approximately $442 million of assets, primarily related to property, plant, and equipment, are subject to lien at December 31, 2017. |
| |
(e) | The acquisition included a fully operational 375-MW natural gas-fired combined-cycle facility. |
| |
(f) | The Company owns 90.1%, with the minority owner, Invenergy Wind Global LLC, owning 9.9%. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 2017 Annual Report
Acquisitions During the Year Ended December 31, 2016
The Company's aggregate purchase price for acquisitions during the year ended December 31, 2016 was approximately $2.3 billion. The total aggregate purchase price including minority ownership contributions and the assumption of non-recourse construction debt to the Company was approximately $2.6 billion for these acquisitions. In connection with the Company's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the year ended December 31, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows:
|
| | | |
| 2016 |
| (in millions) |
CWIP | $ | 2,354 |
|
Property, plant, and equipment | 302 |
|
Intangible assets (a) | 128 |
|
Other assets | 52 |
|
Accounts payable | (16 | ) |
Debt | (217 | ) |
Total purchase price | $ | 2,603 |
|
| |
Funded by: | |
The Company (b) (c) | $ | 2,345 |
|
Noncontrolling interests (d) (e) | 258 |
|
Total purchase price | $ | 2,603 |
|
| |
(a) | Intangible assets consist of acquired PPAs that will be amortized over 10- and 20-year terms. The estimated amortization for future periods is approximately $9 million per year. See Note 1 for additional information. |
| |
(b) | At December 31, 2016, $461 million is included in acquisitions payable on the consolidated balance sheets. |
| |
(c) | Includes approximately $281 million of contingent consideration, of which $29 million was payable at December 31, 2017. |
| |
(d) | Includes approximately $51 million of non-cash contributions recorded as capital contributions from noncontrolling interests in the consolidated statements of stockholders' equity. |
| |
(e) | Includes approximately $142 million of contingent consideration, all of which had been paid at December 31, 2016 by the noncontrolling interests. |
NOTES (continued)
Southern Power Company and Subsidiary Companies 20152017 Annual Report
11.12. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 20152017 and 20142016 is as follows:
|
| | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Net Income Attributable to the Company |
| (in millions) |
March 2015 | $ | 348 |
| | $ | 67 |
| | $ | 33 |
|
June 2015 | 337 |
| | 75 |
| | 46 |
|
September 2015 | 401 |
| | 129 |
| | 102 |
|
December 2015 | 304 |
| | 55 |
| | 34 |
|
| | | | | |
March 2014 | $ | 351 |
| | $ | 59 |
| | $ | 33 |
|
June 2014 | 329 |
| | 51 |
| | 31 |
|
September 2014 | 435 |
| | 105 |
| | 64 |
|
December 2014 | 386 |
| | 40 |
| | 44 |
|
|
| | | | | | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income | | Income Tax (Benefit) | | Net Income Attributable to the Company |
| (in millions) |
March 2017 | $ | 450 |
| | $ | 65 |
| | $ | (52 | ) | | $ | 70 |
|
June 2017 | 529 |
| | 112 |
| | (38 | ) | | 82 |
|
September 2017 | 618 |
| | 159 |
| | (39 | ) | | 124 |
|
December 2017 (*) | 478 |
| | 32 |
| | (810 | ) | | 795 |
|
| | | | | | | |
March 2016 | $ | 315 |
| | $ | 47 |
| | $ | (23 | ) | | $ | 50 |
|
June 2016 | 373 |
| | 81 |
| | (41 | ) | | 89 |
|
September 2016 | 500 |
| | 134 |
| | (102 | ) | | 176 |
|
December 2016 | 389 |
| | 28 |
| | (29 | ) | | 23 |
|
| |
(*) | As a result of the Tax Reform Legislation, the Company recorded an income tax benefit of $743 million in the fourth quarter 2017. See Note 5 for additional information. |
The Company's business is influenced by seasonal weather conditions.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2011-20152013-2017
Southern Power Company and Subsidiary Companies 20152017 Annual Report
| | | 2015 |
| | 2014 |
| | 2013 |
| | 2012 |
| | 2011 |
| 2017 |
| | 2016 |
| | 2015 |
| | 2014 |
| | 2013 |
|
Operating Revenues (in millions): | | | | | | | | | | | | | | | | | | |
Wholesale — non-affiliates | $ | 964 |
| | $ | 1,116 |
| | $ | 923 |
| | $ | 754 |
| | $ | 871 |
| $ | 1,671 |
| | $ | 1,146 |
| | $ | 964 |
| | $ | 1,116 |
| | $ | 923 |
|
Wholesale — affiliates | 417 |
| | 383 |
| | 346 |
| | 425 |
| | 359 |
| 392 |
| | 419 |
| | 417 |
| | 383 |
| | 346 |
|
Total revenues from sales of electricity | 1,381 |
| | 1,499 |
| | 1,269 |
| | 1,179 |
| | 1,230 |
| 2,063 |
| | 1,565 |
| | 1,381 |
| | 1,499 |
| | 1,269 |
|
Other revenues | 9 |
| | 2 |
| | 6 |
| | 7 |
| | 6 |
| 12 |
| | 12 |
| | 9 |
| | 2 |
| | 6 |
|
Total | $ | 1,390 |
| | $ | 1,501 |
| | $ | 1,275 |
| | $ | 1,186 |
| | $ | 1,236 |
| $ | 2,075 |
| | $ | 1,577 |
| | $ | 1,390 |
| | $ | 1,501 |
| | $ | 1,275 |
|
Net Income Attributable to the Company (in millions) | $ | 215 |
| | $ | 172 |
| | $ | 166 |
| | $ | 175 |
| | $ | 162 |
| |
Net Income Attributable to Southern Power (in millions)(a) | | $ | 1,071 |
| | $ | 338 |
| | $ | 215 |
| | $ | 172 |
| | $ | 166 |
|
Cash Dividends on Common Stock (in millions) | $ | 131 |
| | $ | 131 |
| | $ | 129 |
| | $ | 127 |
| | $ | 91 |
| $ | 317 |
| | $ | 272 |
| | $ | 131 |
| | $ | 131 |
| | $ | 129 |
|
Return on Average Common Equity (percent)(a) | 10.16 |
| | 10.39 |
| | 10.73 |
| | 11.72 |
| | 11.88 |
| 22.39 |
| | 9.79 |
| | 10.16 |
| | 10.39 |
| | 10.73 |
|
Total Assets (in millions)(b)(c) | $ | 8,905 |
| | $ | 5,233 |
| | $ | 4,417 |
| | $ | 3,771 |
| | $ | 3,569 |
| $ | 15,206 |
| | $ | 15,169 |
| | $ | 8,905 |
| | $ | 5,233 |
| | $ | 4,417 |
|
Gross Property Additions and Acquisitions (in millions) | $ | 1,005 |
| | $ | 942 |
| | $ | 633 |
| | $ | 241 |
| | $ | 255 |
| |
Property, Plant, and Equipment — In Service (in millions) | | $ | 13,755 |
| | $ | 12,728 |
| | $ | 7,275 |
| | $ | 5,657 |
| | $ | 4,696 |
|
Capitalization (in millions): | | | | | | | | | | | | | | | | | | |
Common stock equity | $ | 2,483 |
| | $ | 1,752 |
| | $ | 1,564 |
| | $ | 1,522 |
| | $ | 1,469 |
| $ | 5,138 |
| | $ | 4,430 |
| | $ | 2,483 |
| | $ | 1,752 |
| | $ | 1,564 |
|
Redeemable noncontrolling interests | 43 |
| | 39 |
| | 29 |
| | 8 |
| | 4 |
| — |
| | 164 |
| | 43 |
| | 39 |
| | 29 |
|
Noncontrolling interests | 781 |
| | 219 |
| | — |
| | — |
| | — |
| 1,360 |
| | 1,245 |
| | 781 |
| | 219 |
| | — |
|
Long-term debt(a) | 2,719 |
| | 1,085 |
| | 1,607 |
| | 1,297 |
| | 1,293 |
| |
Long-term debt(b) | | 5,071 |
| | 5,068 |
| | 2,719 |
| | 1,085 |
| | 1,607 |
|
Total (excluding amounts due within one year) | $ | 6,026 |
| | $ | 3,095 |
| | $ | 3,200 |
| | $ | 2,827 |
| | $ | 2,766 |
| $ | 11,569 |
| | $ | 10,907 |
| | $ | 6,026 |
| | $ | 3,095 |
| | $ | 3,200 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | | | | | | | |
Common stock equity | 41.2 |
| | 56.6 |
| | 48.9 |
| | 53.8 |
| | 53.1 |
| 44.4 |
| | 40.6 |
| | 41.2 |
| | 56.6 |
| | 48.9 |
|
Redeemable noncontrolling interests | 0.7 |
| | 1.3 |
| | 0.9 |
| | 0.3 |
| | 0.1 |
| — |
| | 1.5 |
| | 0.7 |
| | 1.3 |
| | 0.9 |
|
Noncontrolling interests | 13.0 |
| | 7.1 |
| | — |
| | — |
| | — |
| 11.8 |
| | 11.4 |
| | 13.0 |
| | 7.1 |
| | — |
|
Long-term debt(a) | 45.1 |
| | 35.0 |
| | 50.2 |
| | 45.9 |
| | 46.8 |
| |
Long-term debt(b) | | 43.8 |
| | 46.5 |
| | 45.1 |
| | 35.0 |
| | 50.2 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Kilowatt-Hour Sales (in millions): | | | | | | | | | | | | | | | | | | |
Wholesale — non-affiliates | 18,544 |
| | 19,014 |
| | 15,111 |
| | 15,637 |
| | 16,090 |
| 35,920 |
| | 23,213 |
| | 18,544 |
| | 19,014 |
| | 15,111 |
|
Wholesale — affiliates | 16,567 |
| | 11,194 |
| | 9,359 |
| | 16,373 |
| | 11,774 |
| 12,811 |
| | 15,950 |
| | 16,567 |
| | 11,194 |
| | 9,359 |
|
Total | 35,111 |
| | 30,208 |
| | 24,470 |
| | 32,010 |
| | 27,864 |
| 48,731 |
| | 39,163 |
| | 35,111 |
| | 30,208 |
| | 24,470 |
|
Plant Nameplate Capacity Ratings (year-end) (megawatts)(c) | 9,808 |
| | 9,185 |
| | 8,924 |
| | 8,764 |
| | 7,908 |
| |
Plant Nameplate Capacity Ratings (year-end) (megawatts) | | 12,940 |
| | 12,442 |
| | 9,808 |
| | 9,185 |
| | 8,924 |
|
Maximum Peak-Hour Demand (megawatts): | | | | | | | | | | | | | | | | | | |
Winter | 3,923 |
| | 3,999 |
| | 2,685 |
| | 3,018 |
| | 3,255 |
| 3,421 |
| | 3,469 |
| | 3,923 |
| | 3,999 |
| | 2,685 |
|
Summer | 4,249 |
| | 3,998 |
| | 3,271 |
| | 3,641 |
| | 3,589 |
| 4,224 |
| | 4,303 |
| | 4,249 |
| | 3,998 |
| | 3,271 |
|
Annual Load Factor (percent) | 49.0 |
| | 51.8 |
| | 54.2 |
| | 48.6 |
| | 51.0 |
| 49.1 |
| | 50.0 |
| | 49.0 |
| | 51.8 |
| | 54.2 |
|
Plant Availability (percent)(d) | 93.1 |
| | 91.8 |
| | 91.8 |
| | 92.9 |
| | 93.9 |
| 99.9 |
| | 91.6 |
| | 93.1 |
| | 91.8 |
| | 91.8 |
|
Source of Energy Supply (percent): | | | | | | | | | | | | | | | | | | |
Natural gas | 89.5 |
| | 86.0 |
| | 88.5 |
| | 91.0 |
| | 89.2 |
| 67.7 |
| | 79.4 |
| | 89.5 |
| | 86.0 |
| | 88.5 |
|
Alternative (Solar, Wind, and Biomass) | 4.3 |
| | 2.9 |
| | 1.1 |
| | 0.5 |
| | 0.2 |
| |
Solar, Wind, and Biomass | | 22.8 |
| | 12.1 |
| | 4.3 |
| | 2.9 |
| | 1.1 |
|
Purchased power — | | | | | | | | | | | | | | | | | | |
From non-affiliates | 4.7 |
| | 6.4 |
| | 6.4 |
| | 7.2 |
| | 6.7 |
| 7.8 |
| | 6.8 |
| | 4.7 |
| | 6.4 |
| | 6.4 |
|
From affiliates | 1.5 |
| | 4.7 |
| | 4.0 |
| | 1.3 |
| | 3.9 |
| 1.7 |
| | 1.7 |
| | 1.5 |
| | 4.7 |
| | 4.0 |
|
Total | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Employees (year-end)(d) | | 541 |
| | — |
| | — |
| | — |
| | — |
|
|
| |
(a) | As a result of the Tax Reform Legislation, the Company recorded an income tax benefit of $743 million in 2017. |
(b) | A reclassification of debt issuance costs from Total Assets to Long-term debt of $11 million $12 million, $9 million, and $10$12 million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with ASU 2015-03. See Note 1 under "Recently Issued Accounting Standards" for additional information.new accounting standards adopted in 2015 and applied retrospectively. |
(b)(c) | A reclassification of deferred tax assets from Total Assets of $306 million $- million, $- million, and $2$- million is reflected for years 2014 2013, 2012, and 2011,2013, respectively, in accordance with new accounting standards adopted in 2015 and applied retrospectively. |
(d) | Prior to the employee transfer in December 2017, the Company had no employees, but was billed employee related costs from SCS. |
SOUTHERN COMPANY GAS
FINANCIAL SECTION
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The management of Southern Company Gas (the Company) is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Under management's supervision, an evaluation of the design and effectiveness of the Company's internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017.
/s/ Andrew W. Evans
Andrew W. Evans
Chairman, President, and Chief Executive Officer
/s/ Elizabeth W. Reese
Elizabeth W. Reese
Executive Vice President, Chief Financial Officer, and Treasurer
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Southern Company Gas and Subsidiary Companies (the Company) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for the year ended December 31, 2017 and the six month periods ended June 30, 2016 (Predecessor) and December 31, 2016 (Successor), and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements (pages II-593 to II-651) present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the year ended December 31, 2017 and the six months ended June 30, 2016 (Predecessor) and December 31, 2016 (Successor), in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), the Company's investment in which is accounted for by the use of the equity method. The accompanying consolidated financial statements of the Company include its equity investment in SNG of $1,262 million and $1,394 million as of December 31, 2017 and December 31, 2016, respectively, and its earnings from its equity method investment in SNG of $88 million and $56 million for the year ended December 31, 2017 and the six months ended December 31, 2016, respectively. Those statements were audited by other auditors whose report (which expresses an unqualified opinion on SNG's financial statements and contains an emphasis of matter paragraph concerning the extent of its operations and relationships with affiliated entities) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the report of the other auditors. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 20, 2018
We have served as the Company's auditor since 2016.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
In our opinion, the consolidated statement of income, comprehensive income, common stockholders' equity, and cash flows present fairly, in all material respects, the results of operations and cash flows of Southern Company Gas (formerly AGL Resources Inc.) and its subsidiaries for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the year ended December 31, 2015 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Atlanta, Georgia
February 11, 2016
|
| |
Term | Meaning |
AFUDC | Allowance for funds used during construction |
ASC | Accounting Standards Codification |
ASU 2015-17. | Accounting Standards Update |
Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
Atlantic Coast Pipeline | Atlantic Coast Pipeline, LLC |
Chattanooga Gas | Chattanooga Gas Company |
Chicago Hub | A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies |
CUB | Citizens Utility Board, in Illinois |
Dalton Pipeline | A 50% undivided ownership interest in a pipeline facility in Georgia |
EBIT | Earnings before interest and taxes |
EPA | U.S. Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
Fitch | Fitch Ratings, Inc. |
GAAP | U.S. generally accepted accounting principles |
Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
Heating Season | The period from November through March when natural gas usage and operating revenues are generally higher |
Horizon Pipeline | Horizon Pipeline Company, LLC |
Illinois Commission | Illinois Commerce Commission |
IRS | Internal Revenue Service |
ITC | Investment tax credit |
LIBOR | London Interbank Offered Rate |
LIFO | Last-in, first-out |
LNG | Liquefied natural gas |
LOCOM | Lower of weighted average cost or current market price |
Marketers | Marketers selling retail natural gas in Georgia and certificated by the Georgia PSC |
Merger | The merger of a wholly-owned, direct subsidiary of Southern Company, with and into Southern Company Gas, effective July 1, 2016, with Southern Company Gas continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company |
MGP | Manufactured gas plant |
mmBtu | Million British thermal units |
Moody's | Moody's Investors Service, Inc. |
natural gas distribution utilities | Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, and Elkton Gas) |
New Jersey BPU | New Jersey Board of Public Utilities |
Nicor Gas | Northern Illinois Gas Company, doing business as Nicor Gas Company |
NYMEX | New York Mercantile Exchange, Inc. |
OCI | Other comprehensive income |
DEFINITIONS
|
| |
Term | Meaning |
PennEast Pipeline | PennEast Pipeline Company, LLC |
Piedmont | Piedmont Natural Gas Company, Inc. |
Pivotal Utility Holdings | Pivotal Utility Holdings, Inc., a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas, Elkton Gas, and Florida City Gas |
PRP | Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013 |
PSC | Public Service Commission |
ROE | Return on equity |
S&P | S&P Global Ratings, a division of S&P Global Inc. |
SCS | Southern Company Services, Inc. (the Southern Company system service company) |
SEC | U.S. Securities and Exchange Commission |
Sequent | Sequent Energy Management, L.P. |
SNG | Southern Natural Gas Company, L.L.C. |
Southern Company | The Southern Company |
Southern Company Gas Capital | Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas |
Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Linc, PowerSecure, Inc. (as of May 9, 2016), and other subsidiaries |
Southern Holdings | Southern Company Holdings, Inc. |
Southern Linc | Southern Communications Services, Inc. |
Southern Nuclear | Southern Nuclear Operating Company, Inc. |
Southern Power | Southern Power Company and its subsidiaries |
SouthStar | SouthStar Energy Services, LLC |
STRIDE | Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program |
traditional electric operating companies | Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company |
Tax Reform Legislation | The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018 |
Triton | Triton Container Investments, LLC |
VIE | Variable interest entity |
Virginia Commission | Virginia State Corporation Commission |
Virginia Natural Gas | Virginia Natural Gas, Inc. |
WACOG | Weighted average cost of gas |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company Gas and Subsidiary Companies 2017 Annual Report
OVERVIEW
Business Activities
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Southern Company Gas and its subsidiaries (the Company) are also involved in several other complementary businesses.
The Company has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment, all other. See Note 12 to the financial statements for additional information.
Many factors affect the opportunities, challenges, and risks of the Company's business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, environmental standards, reliability, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Company for the foreseeable future.
Merger, Acquisition, and Disposition Activities
On July 1, 2016, the Company completed the Merger, pursuant to which the Company became a wholly-owned subsidiary of Southern Company. Southern Company accounted for the Merger using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for the Company's assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note 11 to the financial statements under "Merger with Southern Company" for additional information.
In September 2016, the Company paid approximately $1.4 billion to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The investment in SNG is accounted for using the equity method. On March 31, 2017, the Company made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 4 to the financial statements under "Equity Method Investments – SNG" and Note 11 to the financial statements under "Investment in SNG" for additional information.
In October 2016, the Company completed its purchase of Piedmont's 15% interest in SouthStar for $160 million. See Note 4 to the financial statements under "Variable Interest Entities" for additional information.
On October 15, 2017, the Company's subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. As of December 31, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.3 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and, as a result, a deferred tax liability has not yet been provided. Through the completion of the asset sales, the Company intends to invest less than $0.1 billion in capital additions required for ordinary business operations of these assets. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. The Company and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
Operating Metrics
The Company continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The Company measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on the Company's distribution system. With the exception of the Company's utilities in Illinois and Florida, the Company has various regulatory mechanisms, such as weather normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia, Illinois, and Ohio can be impacted by warmer- or colder-than-normal weather. The Company utilizes weather hedges to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside for these businesses.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.
The Company's natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
See RESULTS OF OPERATIONS herein for additional information on these operating metrics.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. The Company's base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing the Company's annual results. Thus, the Company's operating results can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below. |
| | | | | | | | | |
| | Percent Generated During Heating Season |
| | Operating Revenues | | EBIT | | Net Income |
Successor - 2017 | | 67.3 | % | | 69.6 | % | | 73.7 | % |
Successor - July 1, 2016 through December 31, 2016 | | 67.1 | % | | 81.5 | % | | 96.5 | % |
Predecessor - January 1, 2016 through June 30, 2016 | | 70.0 | % | | 107.0 | % | | 138.9 | % |
Predecessor - 2015 | | 68.1 | % | | 77.3 | % | | 85.0 | % |
Earnings
Net income attributable to the Company for the successor year ended December 31, 2017 was $243 million, which included net income of $53 million from the Company's investment in SNG (including $18 million related to a non-cash charge recorded by SNG to establish a regulatory liability associated with the Tax Reform Legislation) and $44 million generated from the Company's continued investment in infrastructure replacement programs and base rate increases at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas, less the associated increases in depreciation. Net income also reflects $130 million of additional tax expense resulting from the revaluation of deferred tax assets of $93 million related to the Tax Reform Legislation and $37 million associated with State of Illinois income tax legislation enacted in the third quarter 2017 and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. Also included in net income was $17 million of additional expense resulting from the pushdown of acquisition accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Notes 5 and 11 to the financial statements for additional information.
Net income attributable to the Company for the successor period of July 1, 2016 through December 31, 2016 was $114 million, which included $26 million in earnings from the SNG investment, net of related interest expense, partially offset by $12 million of additional expense resulting from the impact of the pushdown of acquisition accounting and $27 million of Merger-related expenses.
Net income attributable to the Company for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $131 million and $353 million, respectively, which included $41 million and $26 million, respectively, of Merger-related expenses, and $14 million and $20 million, respectively, of net income attributable to the SouthStar
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
noncontrolling interest, which the Company purchased in October 2016. Net income for the predecessor periods reflected higher revenues from continued investment in infrastructure programs, partially offset by warm weather, net of hedging, and low earnings from wholesale gas services due to mark-to-market losses.
RESULTS OF OPERATIONS
Operating Results
A condensed income statement for the Company follows: |
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | Year Ended December 31, |
| 2017 | | 2016 | | | 2016 | | 2015 |
| (in millions) | | | (in millions) |
Operating revenues | $ | 3,920 |
| | $ | 1,652 |
| | | $ | 1,905 |
| | $ | 3,941 |
|
Cost of natural gas and other sales | 1,630 |
| | 623 |
| | | 769 |
| | 1,645 |
|
Other operations and maintenance | 940 |
| | 482 |
| | | 454 |
| | 928 |
|
Depreciation and amortization | 501 |
| | 238 |
| | | 206 |
| | 397 |
|
Taxes other than income taxes | 184 |
| | 71 |
| | | 99 |
| | 181 |
|
Merger-related expenses | — |
| | 41 |
| | | 56 |
| | 44 |
|
Total operating expenses | 3,255 |
| | 1,455 |
| | | 1,584 |
| | 3,195 |
|
Operating income | 665 |
| | 197 |
| | | 321 |
| | 746 |
|
Earnings from equity method investments | 106 |
| | 60 |
| | | 2 |
| | 6 |
|
Interest expense, net of amounts capitalized | 200 |
| | 81 |
| | | 96 |
| | 175 |
|
Other income (expense), net | 39 |
| | 14 |
| | | 5 |
| | 9 |
|
Earnings before income taxes | 610 |
| | 190 |
| | | 232 |
| | 586 |
|
Income taxes | 367 |
| | 76 |
| | | 87 |
| | 213 |
|
Net Income | 243 |
| | 114 |
| | | 145 |
| | 373 |
|
Less: Net income attributable to noncontrolling interest | — |
| | — |
| | | 14 |
| | 20 |
|
Net Income Attributable to Southern Company Gas | $ | 243 |
| | $ | 114 |
| | | $ | 131 |
| | $ | 353 |
|
Operating Revenues
Operating revenues for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 were $3.9 billion and $1.7 billion, respectively. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, operating revenues were $1.9 billion and $3.9 billion, respectively.
For the successor year ended December 31, 2017, natural gas revenues included recovery of $1.6 billion in cost of natural gas and $6 million in net revenues from wholesale gas services, net of $21 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues for the successor year ended December 31, 2017 were $99 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas. Natural gas revenues were partially offset by a $13 million negative impact of warmer-than-normal weather, net of hedging.
For the successor period of July 1, 2016 through December 31, 2016, natural gas revenues included recovery of $613 million in cost of natural gas and $24 million in net revenues from wholesale gas services, net of $5 million of amortization associated with assets established in the application of acquisition accounting. Natural gas revenues were partially offset by a $5 million decrease attributable to warmer-than-normal weather, net of hedging.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, natural gas revenues included recovery of $755 million and $1.6 billion, respectively, in cost of natural gas, as well as $32 million in net losses and $202 million in net revenues, respectively, from wholesale gas services. For the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included a negative impact of $7 million attributable to warmer-than-normal weather,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
net of hedging. For the predecessor year ended December 31, 2015, natural gas revenues included a positive impact of $2 million also attributable to warmer-than-normal weather, net of hedging.
See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.
Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact during the non-Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where the Company's operations are impacted by weather.
|
| | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | 2017 vs. normal | | 2017 vs. 2016 | | 2016 vs. 2015 |
| | Normal(a) | | 2017 | | 2016 | | 2015 | | (warmer) | | colder (warmer) | | (warmer) |
| | (in thousands) | | | | | | |
Illinois(b) | | 5,869 |
| | 5,246 |
| | 5,243 |
| | 5,433 |
| | (10.6 | )% | | 0.1 | % | | (3.5 | )% |
Georgia | | 2,614 |
| | 1,970 |
| | 2,175 |
| | 2,204 |
| | (24.6 | )% | | (9.4 | )% | | (1.3 | )% |
| |
(a) | Normal represents the 10-year average from January 1, 2007 through December 31, 2016 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
| |
(b) | The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 5,600 annually from 1998 through 2007. |
The Company hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $4 million ($2 million after tax), $1 million ($1 million after tax), $7 million ($5 million after tax), and a positive impact of $2 million ($1 million after tax) for the successor year ended December 31, 2017, the successor period of July 1, 2016 through December 31, 2016, the predecessor period of January 1, 2016 through June 30, 2016, and the predecessor year ended December 31, 2015, respectively.
The Company also hedged its exposure to warmer-than-normal weather at gas marketing services in Georgia and Illinois; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $9 million ($5 million after tax) and $4 million ($3 million after tax) for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, respectively. There was no weather impact for the predecessor period of January 1, 2016 through June 30, 2016 or the predecessor year ended December 31, 2015.
The following table provides the number of customers served by the Company for the periods presented:
|
| | | | | | | | | |
| | December 31, |
| | 2017(a) | | 2016(a) | | 2015(b) |
| | (in thousands, except market share %) |
Gas distribution operations | | 4,623 |
| | 4,586 |
| | 4,526 |
|
Gas marketing services | | | | | | |
Energy customers(c) | | 774 |
| | 656 |
| | 645 |
|
Market share of energy customers in Georgia | | 29.2 | % | | 29.6 | % | | 29.7 | % |
Service contracts | | 1,184 |
| | 1,198 |
| | 1,171 |
|
| |
(a) | Includes customer and contract counts at December 31, 2017 and 2016. |
| |
(b) | Includes average customer and contract counts for the year ended December 31, 2015. |
| |
(c) | Includes approximately 140,000 customers at December 31, 2017 that were contracted to serve beginning April 1, 2017. |
The Company anticipates overall customer growth trends at gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices. The Company uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Gas marketing services' market share in Georgia decreased at December 31, 2017 compared to the two prior years as a result of a highly competitive marketing environment, which is expected to continue for the foreseeable future. The Company will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Cost of Natural Gas and Other Sales
Natural gas costs are the largest expense for the Company. Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, gas distribution operations charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Gas distribution operations defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 79.6% of total cost of natural gas for 2017.
Gas marketing services customers are charged for actual or estimated natural gas consumed. Cost of natural gas includes the cost of fuel, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives.
Cost of natural gas was $1.6 billion for the successor year ended December 31, 2017, which reflected an increase in natural gas pricing of 26.3% during the year compared to 2016, partially offset by lower demand for natural gas.
For the successor period of July 1, 2016 through December 31, 2016, cost of natural gas was $613 million and reflected low demand for natural gas driven by warm weather in the fourth quarter 2016.
Cost of natural gas was $755 million and $1.6 billion for the predecessor period of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, respectively, and reflected low demand for natural gas driven by warm weather during those periods.
The following table details the volumes of natural gas sold during all periods presented. |
| | | | | | | | | | | | | | | |
| | Year Ended December 31, | | 2017 vs. 2016 | | 2016 vs. 2015 |
| | 2017 | | 2016 | | 2015 | | % Change | | % Change |
Gas distribution operations (mmBtu in millions) | | | | | | | | | | |
Firm | | 667 |
| | 670 |
| | 695 |
| | (0.4 | )% | | (3.6 | )% |
Interruptible | | 95 |
| | 96 |
| | 99 |
| | (1.0 | )% | | (3.0 | )% |
Total | | 762 |
| | 766 |
| | 794 |
| | (0.5 | )% | | (3.5 | )% |
Gas marketing services (mmBtu in millions) | | | | | | | | | | |
Firm: | | | | | | | | | | |
Georgia | | 23 |
| | 34 |
| | 35 |
| | (32.4 | )% | | (2.9 | )% |
Illinois | | 8 |
| | 12 |
| | 13 |
| | (33.3 | )% | | (7.7 | )% |
Other emerging markets | | 15 |
| | 12 |
| | 11 |
| | 25.0 | % | | 9.1 | % |
Interruptible large commercial and industrial | | 11 |
| | 14 |
| | 14 |
| | (21.4 | )% | | — | % |
Total | | 57 |
| | 72 |
| | 73 |
| | (20.8 | )% | | (1.4 | )% |
Wholesale gas services | | | | | | | | | | |
Daily physical sales (mmBtu in millions/day) | | 6.4 |
| | 7.4 |
| | 6.8 |
| | (13.5 | )% | | 8.8 | % |
Other Operations and Maintenance Expenses
For the successor year ended December 31, 2017, other operations and maintenance expenses were $940 million and primarily reflected compensation and benefit costs and professional services, including pipeline compliance and maintenance and legal services.
For the successor period of July 1, 2016 through December 31, 2016, other operations and maintenance expenses were $482 million and primarily reflected compensation and benefit costs and professional services, including pipeline compliance and maintenance and legal services.
For the predecessor period of January 1, 2016 through June 30, 2016, other operations and maintenance expenses were $454 million consistent with the level of expenses in the corresponding period in 2015.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
For the predecessor year ended December 31, 2015, other operations and maintenance expenses were $928 million and included pipeline compliance and maintenance costs, compensation and benefit costs, and a $14 million goodwill impairment charge. See ACCOUNTING POLICIES – "Assessment of Assets" herein and Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information on the goodwill impairment charge.
Depreciation and Amortization
For the successor year ended December 31, 2017, depreciation and amortization was $501 million and included $38 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, primarily at gas marketing services and $28 million in additional depreciation at gas distribution operations, primarily due to continued investment in infrastructure programs.
For the successor period of July 1, 2016 through December 31, 2016, depreciation and amortization was $238 million and included $23 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, primarily at gas marketing services, as well as depreciation at gas distribution operations due to continued investment in infrastructure programs.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, depreciation and amortization was $206 million and $397 million, respectively, and reflected depreciation related to additional assets placed in service at gas distribution operations due to continued investment in infrastructure programs.
See Notes 3 and 11 to the financial statements under "Regulatory Matters – Regulatory Infrastructure Programs" and "Merger with Southern Company," respectively, for additional information on infrastructure programs and the application of acquisition accounting.
Taxes Other Than Income Taxes
For the successor year ended December 31, 2017, taxes other than income taxes were $184 million, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes.
For the successor period of July 1, 2016 through December 31, 2016, taxes other than income taxes were $71 million, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, taxes other than income taxes were $99 million and $181 million, respectively, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes.
Merger-Related Expenses
There were no Merger-related expenses in the successor year ended December 31, 2017.
For the successor period of July 1, 2016 through December 31, 2016, Merger-related expenses were $41 million, including $18 million in rate credits provided to the customers of Elizabethtown Gas and Elkton Gas as conditions of the Merger, $20 million for additional compensation-related expenses, and $3 million for financial advisory fees, legal expenses, and other Merger-related costs.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, Merger-related expenses were $56 million and $44 million, respectively, including $31 million and $20 million, respectively, for financial advisory fees, legal expenses, and other Merger-related costs, and $25 million and $24 million, respectively, for additional compensation-related expenses.
See Note 11 to the financial statements under "Merger with Southern Company" for additional information.
Earnings from Equity Method Investments
For the successor year ended December 31, 2017, earnings from equity method investments were $106 million, reflecting $88 million in earnings from the Company's investment in SNG, including $33 million related to a non-cash charge recorded by SNG to establish a regulatory liability associated with the Tax Reform Legislation, and $18 million in earnings from all other investments.
For the successor period of July 1, 2016 through December 31, 2016, earnings from equity method investments were $60 million, reflecting $56 million in earnings from the Company's investment in SNG and $4 million in earnings from all other investments.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, earnings from equity method investments were not material.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
See Notes 4 and 11 to the financial statements under "Equity Method Investments" and "Investment in SNG," respectively, for additional information on the Company's investment in SNG.
Interest Expense, Net of Amounts Capitalized
For the successor year ended December 31, 2017, interest expense, net of amounts capitalized was $200 million, which includes the $38 million fair value adjustment on long-term debt in acquisition accounting. Interest expense also reflects debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.
For the successor period of July 1, 2016 through December 31, 2016, interest expense, net of amounts capitalized was $81 million, which includes the $19 million fair value adjustment on long-term debt in acquisition accounting. Interest expense also reflects debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, interest expense, net of amounts capitalized was $96 million and $175 million, respectively, reflecting debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.
See FUTURE EARNINGS POTENTIAL – "Unrecognized Ratemaking Amounts" herein for additional information on the unrecognized costs related to the infrastructure programs. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 6 to the financial statements for additional information on outstanding debt.
Other Income (Expense), Net
For the successor year ended December 31, 2017, other income (expense), net was $39 million and primarily related to a $20 million gain from the settlement of contractor litigation claims, tax gross-up on contributions in aid of construction, and AFUDC. See Note 3 to the financial statements under "Regulatory Matters – PRP Settlement" for additional information on contractor litigation claims.
For the successor period of July 1, 2016 through December 31, 2016, other income (expense), net was $14 million and primarily related to the tax gross-up of contributions in aid of construction received from customers.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, other income (expense), net was not material.
Income Taxes
For the successor year ended December 31, 2017, income taxes were $367 million. The effective tax rate in 2017 reflects additional expense from the revaluation of deferred tax assets of $93 million associated with the Tax Reform Legislation and $37 million associated with State of Illinois income tax legislation enacted in the third quarter 2017 and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings.
For the successor period of July 1, 2016 through December 31, 2016, income taxes were $76 million. The effective tax rate during this period reflects certain nondeductible Merger-related charges.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, income taxes were $87 million and $213 million, respectively. The effective tax rate in both periods reflects certain nondeductible Merger-related expenses and other charges.
The effective tax rate for each period presented is consistent when adjusted for the additional expense recorded from the revaluation of deferred tax assets associated with the Tax Reform Legislation, the State of Illinois income tax legislation enacted in the third quarter 2017, the allocation of new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings in 2017, and the nondeductible Merger-related charges for each period in 2017, 2016, and 2015.
See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information.
Noncontrolling Interest
Prior to the October 2016 acquisition of Piedmont's 15% interest in SouthStar, net income attributable to noncontrolling interest was recorded on the statements of income and totaled $14 million and $20 million in the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, respectively. See Note 4 to the financial statements under
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
"Variable Interest Entities" for additional information.
Effects of Inflation
The Company is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on the Company's results of operations has not been substantial in recent years.
Performance and Non-GAAP Measures
Prior to the Merger, the Company evaluated segment performance using EBIT, which includes operating income, earnings from equity method investments, and other income (expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of the Company's segments for the predecessor periods, as EBIT was the primary measure of segment profit or loss for those periods. Subsequent to the Merger, the Company changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the year ended December 31, 2017 and the period of July 1, 2016 through December 31, 2016 presented herein is considered a non-GAAP measure. The Company also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. The Company further believes the presentation of segment EBIT for the year ended December 31, 2017 and the period of July 1, 2016 through December 31, 2016 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. The Company further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, the Company's operating performance than net income attributable to the Company or operating income as determined in accordance with GAAP. In addition, the Company's adjusted operating margin may not be comparable to similarly titled measures of other companies.
See RESULTS OF OPERATIONS herein for information on the Company's financial performance.
Reconciliations of operating income to adjusted operating margin and net income attributable to Southern Company Gas to EBIT are as follows: |
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | Year Ended December 31, |
| 2017 | | 2016 | | | 2016 | | 2015 |
| (in millions) | | | (in millions) |
Operating Income | $ | 665 |
| | $ | 197 |
| | | $ | 321 |
| | $ | 746 |
|
Other operating expenses(a) | 1,625 |
| | 832 |
| | | 815 |
| | 1,550 |
|
Revenue tax expense(b) | (98 | ) | | (31 | ) | | | (56 | ) | | (101 | ) |
Adjusted Operating Margin | $ | 2,192 |
| | $ | 998 |
| | | $ | 1,080 |
| | $ | 2,195 |
|
| |
(a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | Year Ended December 31, |
| 2017 | | 2016 | | | 2016 | | 2015 |
| (in millions) | | | (in millions) |
Net Income Attributable to Southern Company Gas | $ | 243 |
| | $ | 114 |
| | | $ | 131 |
| | $ | 353 |
|
Net income attributable to noncontrolling interest | — |
| | — |
| | | 14 |
| | 20 |
|
Income taxes | 367 |
| | 76 |
| | | 87 |
| | 213 |
|
Interest expense, net of amounts capitalized | 200 |
| | 81 |
| | | 96 |
| | 175 |
|
EBIT | $ | 810 |
| | $ | 271 |
| | | $ | 328 |
| | $ | 761 |
|
Segment Information
Adjusted operating margin, operating expenses, and the Company's primary performance metric for each segment are illustrated in the tables below. |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 |
| | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income |
| | (in millions) | | (in millions) |
Gas distribution operations | | $ | 1,834 |
| | $ | 1,184 |
| | $ | 353 |
| | $ | 817 |
| | $ | 595 |
| | $ | 77 |
|
Gas marketing services | | 313 |
| | 200 |
| | 84 |
| | 139 |
| | 112 |
| | 19 |
|
Wholesale gas services | | 5 |
| | 56 |
| | (57 | ) | | 24 |
| | 26 |
| | — |
|
Gas midstream operations | | 42 |
| | 52 |
| | 3 |
| | 19 |
| | 26 |
| | 20 |
|
All other | | 10 |
| | 47 |
| | (140 | ) | | 3 |
| | 46 |
| | (2 | ) |
Intercompany eliminations | | (12 | ) | | (12 | ) | | — |
| | (4 | ) | | (4 | ) | | — |
|
Consolidated | | $ | 2,192 |
| | $ | 1,527 |
| | $ | 243 |
| | $ | 998 |
| | $ | 801 |
| | $ | 114 |
|
| |
(*) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Predecessor |
| | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
| | Adjusted Operating Margin(*) | | Operating Expenses(*) | | EBIT | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | EBIT |
| | (in millions) | | (in millions) |
Gas distribution operations | | $ | 911 |
| | $ | 560 |
| | $ | 353 |
| | $ | 1,657 |
| | $ | 1,086 |
| | $ | 581 |
|
Gas marketing services | | 190 |
| | 81 |
| | 109 |
| | 317 |
| | 165 |
| | 152 |
|
Wholesale gas services | | (36 | ) | | 33 |
| | (68 | ) | | 183 |
| | 71 |
| | 110 |
|
Gas midstream operations | | 15 |
| | 24 |
| | (6 | ) | | 36 |
| | 62 |
| | (23 | ) |
All other | | 4 |
| | 65 |
| | (60 | ) | | 7 |
| | 70 |
| | (59 | ) |
Intercompany eliminations | | (4 | ) | | (4 | ) | | — |
| | (5 | ) | | (5 | ) | | — |
|
Consolidated | | $ | 1,080 |
| | $ | 759 |
| | $ | 328 |
| | $ | 2,195 |
| | $ | 1,449 |
| | $ | 761 |
|
| |
(*) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers. |
Gas Distribution Operations
Gas distribution operations is the largest component of the Company's business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provide the Company with the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest, maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, the Company's second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. The Company has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas distribution utilities' service territories.
Successor Year Ended December 31, 2017
Net income of $353 million includes $1.8 billion in adjusted operating margin, $1.2 billion in operating expenses, and $34 million in other income (expense), net, which resulted in EBIT of $684 million. Net income also includes $153 million in interest expense, net of amounts capitalized and $178 million in income tax expense. Adjusted operating margin reflects $99 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas. Adjusted operating margin was also affected by increased customer growth, partially offset by the negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $28 million increase in depreciation associated with additional assets placed in service, as well as benefit and compensation costs, legal expenses, and pipeline compliance and maintenance expenses. Other income (expense), net reflects a $20 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017 and November 1, 2017. Income tax expense includes a $22 million benefit as a result of the Tax Reform Legislation.
See Note 3 to the financial statements under "Regulatory Matters – PRP Settlement" for additional information on contractor litigation claims. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 6 to the financial statements for additional information on debt issuances. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information.
Successor Period of July 1, 2016 through December 31, 2016
Net income of $77 million includes $817 million in adjusted operating margin, $595 million in operating expenses, and $11 million in other income (expense), net, resulting in EBIT of $233 million. Net income also includes $105 million in interest expense, net of amounts capitalized and $51 million in income tax expense. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs, partially offset by the impact of warm weather, net of hedging. Operating expenses reflect the depreciation associated with additional assets placed in service, the related expenses associated with pipeline compliance and maintenance activities, and $18 million of rate credits provided to the customers of Elizabethtown Gas and Elkton Gas as conditions of the Merger. See Note 11 to the financial statements under "Merger with Southern Company" for additional information.
Predecessor Period of January 1, 2016 through June 30, 2016
EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expense, and $2 million in other income (expense), net. Adjusted operating margin reflects increased revenue from continued investment in infrastructure replacement programs and the impact of customer usage and growth, partially offset by the impact of warm weather, net of hedging. Operating expenses reflect the depreciation associated with additional assets placed in service.
Predecessor Year Ended December 31, 2015
EBIT of $581 million includes $1.7 billion in adjusted operating margin, $1.1 billion in operating expense, and $10 million in other income (expense), net. Adjusted operating margin reflects revenue from the continued investment in infrastructure replacement programs, the impact of customer usage and growth, and the impact of warm weather, net of hedging. Operating expenses reflect the depreciation associated with additional assets placed in service, as well as benefits and compensation costs.
Gas Marketing Services
Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, customer care, and bad debt expenses.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Successor Year Ended December 31, 2017
Net income of $84 million includes $313 million in adjusted operating margin and $200 million in operating expenses, which resulted in EBIT of $113 million. Net income also includes $5 million in interest expense, net of amounts capitalized and $24 million in income tax expense. Adjusted operating margin reflects a $9 million negative impact of warmer-than-normal weather, net of hedging, and $4 million in unrealized hedge losses, net of recoveries. Operating expenses includes $40 million in additional amortization of intangible assets established in the application of acquisition accounting. Income tax expense includes a $19 million benefit as a result of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information.
Successor Period of July 1, 2016 through December 31, 2016
Net income of $19 million includes $139 million in adjusted operating margin and $112 million in operating expenses, resulting in EBIT of $27 million. Net income also includes $1 million in interest expense, net of amounts capitalized and $7 million in income tax expense. Adjusted operating margin reflects a reduction of $5 million due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin are unrealized hedge gains and LOCOM adjustments. Operating expenses reflect $23 million in additional amortization of intangible assets, partially offset by a $2 million reduction in operations and maintenance expense due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. See Note 1 to the financial statements under "Natural Gas for Sale" for additional information on LOCOM adjustments and Note 11 to the financial statements for additional information on the Merger.
Predecessor Period of January 1, 2016 through June 30, 2016
EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Operating expenses reflect lower bad debt, marketing, and depreciation and amortization, compared to the same period in the prior year. Earnings also include $14 million attributable to noncontrolling interest.
Predecessor Year Ended December 31, 2015
EBIT of $152 million includes $317 million in adjusted operating margin and $165 million in operating expenses. Adjusted operating margin reflects revenue from gas marketing and warranty sales, which were partially offset by the impact of warm weather, net of hedging. Operating expenses primarily reflect compensation and benefits costs. Earnings also include $20 million attributable to noncontrolling interest.
Wholesale Gas Services
Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. The Company has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Wholesale gas services generated positive economic results for the successor year ended December 31, 2017, primarily reflecting lower volatility market conditions throughout the majority of 2017 and higher volatility along with the widening of locational and transportation spreads in December 2017 due to colder weather, as well as higher natural gas storage value resulting from higher natural gas prices.
Successor Year Ended December 31, 2017
Net loss of $57 million includes $5 million in adjusted operating margin, $56 million in operating expenses, and $1 million in other income (expense), net, which resulted in a loss before interest and taxes of $50 million. Also included are $7 million in interest expense, net of amounts capitalized. Adjusted operating margin reflects a decrease of $21 million due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin is revenue from commercial activity partially offset by mark-to-market losses. Income tax expense includes $21 million resulting from the revaluation of deferred income tax assets associated with the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information on income taxes.
Successor Period of July 1, 2016 through December 31, 2016
Net income includes $24 million in adjusted operating margin, $26 million in operating expenses, and $2 million in other income (expense), net, resulting in no EBIT. Also included are $3 million in interest expense, net of amounts capitalized and $3 million in income tax benefit. Adjusted operating margin reflects a decrease of $5 million due to fair value adjustments to certain assets and
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin are mark-to-market gains due to changes in natural gas prices in the fourth quarter 2016 and losses from commercial activity due to low volatility in natural gas prices and warm weather. Operating expenses reflect low incentive compensation expense due to low earnings.
Predecessor Period of January 1, 2016 through June 30, 2016
Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expense, and $1 million in other income (expense), net. Adjusted operating margin reflects mark-to-market losses and LOCOM adjustments as a result of changes in natural gas prices and revenues from commercial activity driven by changes in price volatility. Operating expenses reflect lower incentive compensation expense as compared to the same period in the prior year due to lower earnings.
Predecessor Year Ended December 31, 2015
EBIT of $110 million includes $183 million in adjusted operating margin, $71 million in operating expenses, and $(2) million in other income (expense), net. Adjusted operating margin reflects revenue from commercial activity driven by changes in price volatility, mark-to-market gains, and LOCOM adjustments as a result of changes in natural gas prices.
The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented: |
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | Year Ended December 31, |
| 2017 | | 2016 | | | 2016 | | 2015 |
| (in millions) | | | (in millions) |
Commercial activity recognized | $ | 116 |
| | $ | (15 | ) | | | $ | 34 |
| | $ | 140 |
|
Gain (loss) on storage derivatives | 23 |
| | (20 | ) | | | (38 | ) | | 45 |
|
Gain (loss) on transportation and forward commodity derivatives | (113 | ) | | 64 |
| | | (31 | ) | | 11 |
|
LOCOM adjustments, net of current period recoveries | — |
| | — |
| | | (1 | ) | | (13 | ) |
Purchase accounting adjustments to fair value inventory and contracts | (21 | ) | | (5 | ) | | | — |
| | — |
|
Adjusted operating margin | $ | 5 |
| | $ | 24 |
| | | $ | (36 | ) | | $ | 183 |
|
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads throughout the majority of 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, during December 2017, significantly colder weather increased natural gas price volatility and transportation spreads widened, enabling wholesale gas services to capture higher commercial activity. Further, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on the Company's customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Transportation and forward commodity derivative losses are primarily the result of widening transportation spreads during the fourth quarter 2017 due to significantly colder weather in the Northeast and Midwest U.S., which impacted forward prices at natural gas receipt and delivery points. Additionally, during 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The natural gas that the Company purchases and injects into storage is accounted for at the LOCOM value utilizing gas daily or spot prices at the end of the year. Wholesale gas services recorded LOCOM adjustments of $19 million for the predecessor year ended December 31, 2015. LOCOM adjustments for all other periods presented were immaterial. See Note 1 to the financial statements under "Natural Gas for Sale" for additional information.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, but are net of the estimated impact of profit sharing under its asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at December 31, 2017. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
|
| | | | | | | | | | |
| Storage Withdrawal | | |
| Total storage (WACOG $2.66) | | Expected net operating gains(a) | | Physical Transportation Transactions – Expected Net Operating Gains(b) |
| (in mmBtu in millions) | | (in millions) | | (in millions) |
2018 | 55.2 |
| | $ | 14 |
| | $ | 70 |
|
2019 and thereafter | 2.3 |
| | 1 |
| | 43 |
|
Total at December 31, 2017 | 57.5 |
| | $ | 15 |
| | $ | 113 |
|
| |
(a) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. Also includes the impact of purchase accounting adjustments to reflect natural gas storage inventory at market value. Excluding the impact of these adjustments, the expected net operating gains at December 31, 2017 would have been $22 million. |
| |
(b) | Represents the periods associated with the transportation derivative (gains) and losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative losses that were previously recognized. |
Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note 4 to the financial statements under "Equity Method Investments" for additional information.
Successor Year Ended December 31, 2017
Net income of $3 million includes $42 million in adjusted operating margin, $52 million in operating expenses, $103 million in earnings from equity method investments, consisting primarily of the Company's equity interest in SNG, including $33 million related to a non-cash charge recorded by SNG to establish a regulatory liability associated with the Tax Reform Legislation, and $4 million in other income, which resulted in EBIT of $97 million. Also included in net income are $33 million in interest expense, net of amounts capitalized and $61 million in income tax expense. Income tax expense includes $27 million resulting from the revaluation of deferred income tax assets associated with the Tax Reform Legislation and $8 million related to the allocation of new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information on income taxes.
Successor Period of July 1, 2016 through December 31, 2016
Net income of $20 million includes $19 million in adjusted operating margin, $26 million in operating expenses, $58 million in earnings from equity method investments, consisting primarily of the Company's September 2016 acquired equity interest in SNG, and $1 million in other income, resulting in EBIT of $52 million. Also included in net income are $16 million in interest expense, net of amounts capitalized and $16 million in income tax expense.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Predecessor Periods of January 1, 2016 through June 30, 2016 and the Year Ended December 31, 2015
Loss before interest and taxes for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $6 million and $23 million, respectively, and reflected a $14 million goodwill impairment charge in 2015.
All Other
All other includes the Company's investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.
Successor Year Ended December 31, 2017
Net loss of $140 million includes $10 million in adjusted operating margin and $47 million in operating expenses. Operating expenses included $26 million of integration-related costs. Interest expense, net of amounts capitalized was $2 million due to the intercompany promissory notes that were executed in December 2016. Income tax expense was $104 million and includes $86 million resulting from the revaluation of deferred tax assets associated with the Tax Reform Legislation and $29 million associated with State of Illinois tax legislation enacted during the third quarter 2017 and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional financing information and FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 5 to the financial statements for additional information on income taxes.
Successor Period of July 1, 2016 through December 31, 2016
Operating expenses included Merger-related expenses of $41 million primarily comprised of compensation-related expenses, financial advisory fees, legal expenses, and other Merger-related costs and $8 million in expenses associated with certain benefit arrangements.
Predecessor Periods of January 1, 2016 through June 30, 2016 and the Year Ended December 31, 2015
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, operating expenses included Merger-related expenses of $56 million and $44 million, respectively. These expenses are primarily comprised of financial advisory and legal expenses as well as additional compensation-related expenses, including acceleration of share-based compensation expenses, and change-in-control compensation charges. See Note 11 to the financial statements under "Merger with Southern Company" for additional information.
Segment Reconciliations
Reconciliations of net income attributable to Southern Company Gas to EBIT for the year ended December 31, 2017 and the period of July 1, 2016 through December 31, 2016, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note 12 to the financial statements for additional segment information.
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Year Ended December 31, 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Net Income (Loss) Attributable to Southern Company Gas | $ | 353 |
| $ | 84 |
| $ | (57 | ) | $ | 3 |
| $ | (140 | ) | $ | — |
| $ | 243 |
|
Income taxes | 178 |
| 24 |
| — |
| 61 |
| 104 |
| — |
| 367 |
|
Interest expense, net of amounts capitalized | 153 |
| 5 |
| 7 |
| 33 |
| 2 |
| — |
| 200 |
|
EBIT | $ | 684 |
| $ | 113 |
| $ | (50 | ) | $ | 97 |
| $ | (34 | ) | $ | — |
| $ | 810 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| July 1, 2016 through December 31, 2016 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Net Income (Loss) Attributable to Southern Company Gas | $ | 77 |
| $ | 19 |
| $ | — |
| $ | 20 |
| $ | (2 | ) | $ | — |
| $ | 114 |
|
Income taxes (benefit) | 51 |
| 7 |
| (3 | ) | 16 |
| 5 |
| — |
| 76 |
|
Interest expense, net of amounts capitalized | 105 |
| 1 |
| 3 |
| 16 |
| (44 | ) | — |
| 81 |
|
EBIT | $ | 233 |
| $ | 27 |
| $ | — |
| $ | 52 |
| $ | (41 | ) | $ | — |
| $ | 271 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| Year Ended December 31, 2017 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 650 |
| $ | 113 |
| $ | (51 | ) | $ | (10 | ) | $ | (37 | ) | $ | — |
| $ | 665 |
|
Other operating expenses(a) | 1,282 |
| 200 |
| 56 |
| 52 |
| 47 |
| (12 | ) | 1,625 |
|
Revenue tax expense(b) | (98 | ) | — |
| — |
| — |
| — |
| — |
| (98 | ) |
Adjusted Operating Margin | $ | 1,834 |
| $ | 313 |
| $ | 5 |
| $ | 42 |
| $ | 10 |
| $ | (12 | ) | $ | 2,192 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Successor |
| July 1, 2016 through December 31, 2016 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 222 |
| $ | 27 |
| $ | (2 | ) | $ | (7 | ) | $ | (43 | ) | $ | — |
| $ | 197 |
|
Other operating expenses(a) | 626 |
| 112 |
| 26 |
| 26 |
| 46 |
| (4 | ) | 832 |
|
Revenue tax expense(b) | (31 | ) | — |
| — |
| — |
| — |
| — |
| (31 | ) |
Adjusted Operating Margin | $ | 817 |
| $ | 139 |
| $ | 24 |
| $ | 19 |
| $ | 3 |
| $ | (4 | ) | $ | 998 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Predecessor |
| January 1, 2016 through June 30, 2016 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 351 |
| $ | 109 |
| $ | (69 | ) | $ | (9 | ) | $ | (61 | ) | $ | — |
| $ | 321 |
|
Other operating expenses(a) | 616 |
| 81 |
| 33 |
| 24 |
| 65 |
| (4 | ) | 815 |
|
Revenue tax expense(b) | (56 | ) | — |
| — |
| — |
| — |
| — |
| (56 | ) |
Adjusted Operating Margin | $ | 911 |
| $ | 190 |
| $ | (36 | ) | $ | 15 |
| $ | 4 |
| $ | (4 | ) | $ | 1,080 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | |
| Predecessor |
| Year Ended December 31, 2015 |
| Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 571 |
| $ | 152 |
| $ | 112 |
| $ | (26 | ) | $ | (63 | ) | $ | — |
| $ | 746 |
|
Other operating expenses(a) | 1,187 |
| 165 |
| 71 |
| 62 |
| 70 |
| (5 | ) | 1,550 |
|
Revenue tax expense(b) | (101 | ) | — |
| — |
| — |
| — |
| — |
| (101 | ) |
Adjusted Operating Margin | $ | 1,657 |
| $ | 317 |
| $ | 183 |
| $ | 36 |
| $ | 7 |
| $ | (5 | ) | $ | 2,195 |
|
| |
(a) | Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment in 2015, and Merger-related expenses. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
FUTURE EARNINGS POTENTIAL
General
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of the Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Company's primary business of natural gas distribution and its complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include the Company's ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, the Company's ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.
Future earnings will be driven primarily by customer growth and are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in the Company's service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Volatility of natural gas prices has a significant impact on the Company's customer rates, long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of the Company's operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018, which among other things, reduces the federal corporate income tax rate to 21% and changes rates of depreciation and the business interest deduction. On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate effective July 1, 2017. In addition, Southern Company calculated new apportionment factors in several states to include the Company in its consolidated tax filings. See "Income Tax Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Notes 3 and 5 to the financial statements for additional information.
As part of its business strategy, the Company regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets. On October 15, 2017, the Company's subsidiary Pivotal Utility Holdings entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc.; the asset sales are expected to be completed by the end of the third quarter 2018. Net income attributable to Elizabethtown Gas and Elkton Gas for the year ended December 31, 2017 was $34 million. However, due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition,
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
customer demand, and general economic conditions, the 2017 net income is not necessarily indicative of the results to be expected for any other period. See BUSINESS – "Seasonality" in Item 1, RISK FACTORS in Item 1A, and Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future results of operations, cash flows, and financial condition. A major portion of these compliance costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of the Company's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas. See Note 3 to the financial statements under "Environmental Matters" for additional information.
Environmental Remediation
The Company is subject to environmental remediation liabilities associated with 46 former MGP sites in five different states. The Company conducts studies to determine the extent of any required cleanup and has recognized the costs to clean up known impacted sites in its financial statements. Accrued environmental remediation costs totaling $388 million were included in the balance sheets at December 31, 2017, $46 million of which is expected to be incurred over the next 12 months. The natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state regulators to recover approved environmental compliance costs through regulatory mechanisms, which covers substantially all of the total accrued remediation costs. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Water Quality
In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all Clean Water Act programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact permitting and reporting requirements associated with the installation, expansion, and maintenance of pipeline projects. On July 27, 2017, the EPA and the Corps proposed to rescind the 2015 WOTUS rule. The WOTUS rule has been stayed by the U.S. Court of Appeals for the Sixth Circuit since late 2015, but on January 22, 2018, the U.S. Supreme Court determined that federal district courts have jurisdiction over the pending challenges to the rule. On February 6, 2018, the EPA and the Corps published a final rule delaying implementation of the 2015 WOTUS rule to 2020.
FERC Matters
The Company is involved in two significant pipeline construction projects within gas midstream operations. These projects, along with the Company's existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. The following table provides an overview of these pipeline projects.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | |
| Miles of Pipe | | Capital Expenditures | | Ownership Interest |
| | | (in millions) | | |
Atlantic Coast Pipeline(a)(b) | 594 |
| | $ | 310 |
| | 5 | % |
PennEast Pipeline(a)(c) | 118 |
| | 276 |
| | 20 | % |
Total | 712 |
| | $ | 586 |
| | |
| |
(a) | Represents the Company's expected capital expenditures and ownership interest, which may change. |
| |
(b) | In 2014, the Company entered into a joint venture to construct and operate a natural gas pipeline that will run from West Virginia through Virginia and into eastern North Carolina to meet the region's growing demand for natural gas. The proposed pipeline project is expected to transport natural gas to customers in Virginia. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval. The joint venture continues to work with state and other federal agencies to obtain the required environmental permits to begin construction. |
| |
(c) | In 2014, the Company entered into a joint venture to construct and operate a natural gas pipeline that will transport low-cost natural gas from the Marcellus Shale area to customers in New Jersey. The Company believes this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters. On January 19, 2018, the PennEast Pipeline project received FERC approval. The joint venture continues to work with state and other federal agencies to obtain the required environmental permits to begin construction. |
On August 1, 2017, the Dalton Pipeline, which serves as an extension of the Transco pipeline system and provides additional natural gas supply to customers in Georgia, was placed in service. The Company has a 50% ownership interest in the Dalton Pipeline. See Note 4 to the financial statements for additional information.
On January 16, 2018, the Georgia PSC approved SNG's purchase of Georgia Power Company's natural gas lateral pipeline serving Plant McDonough Units 4 through 6 at net book value. Pursuant to this approval, legal transfer of the lateral pipeline is expected to occur in the fourth quarter 2018 and payment of $142 million is expected to occur in the first quarter 2020. During this interim period, Georgia Power Company will receive a discounted shipping rate to reflect the delayed consideration. Completion of this sale is contingent on certain conditions being satisfied by SNG that include, among other things, expansion of the existing lateral pipeline. The Company's portion of the expected capital expenditures for this project is $120 million. On February 15, 2018, FERC approval was obtained. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
Utility Regulation and Rate Design
The natural gas distribution utilities are subject to regulations and oversight by their respective state regulatory agencies for the rates charged to their customers, maintenance of accounting records, and various service and safety matters. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE. Rate base generally consists of the original cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.
The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia PSC. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:
distributing natural gas for Marketers;
constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;
reading meters and maintaining underlying customer premise information for Marketers; and
planning and contracting for capacity on interstate transportation and storage systems.
Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent.
With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. The Company has various mechanisms, such as weather normalization mechanisms and weather derivative instruments, at most of its utilities that limit exposure to weather changes within typical ranges in these utilities' respective service territories.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC specific to Georgia's deregulated market. In addition to natural gas recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. Three of the utilities have decoupled regulatory mechanisms that the Company believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flows. See Note 3 to the financial statements under "Regulatory Matters" for additional information.
The following table provides regulatory information for the Company's six largest natural gas distribution utilities:
|
| | | | | | | | | | | |
| Nicor Gas | | Atlanta Gas Light | | Elizabethtown Gas | | Virginia Natural Gas | | Florida City Gas | | Chattanooga Gas |
Authorized ROE(a)(b) | 9.80% | | 10.75% | | 9.60% | | 9.50% | | 11.25% | | 10.05% |
Weather normalization(c) | | | | | ü | | ü | | | | ü |
Decoupled, including straight-fixed- variable rates(d) | | | ü | | | | ü | | | | ü |
Regulatory infrastructure program rates(e) | ü | |
| |
| | ü | | ü | | |
Bad debt rider(f) | ü | | | | | | ü | | | | ü |
Energy efficiency plan(g) | ü | | | | ü | | ü | | ü | | ü |
Last decision on change in rates(h) | 2018 | | 2017 | | 2017 | | 2017 | | 2004 | | 2010 |
| |
(a) | Represents the authorized ROE, or the midpoint of the authorized ROE range, at December 31, 2017, except Nicor Gas which represents the authorized ROE established in the January 31, 2018 order issued by the Illinois Commission. The authorized ROE of Nicor Gas at December 31, 2017 was 10.17%. See "Base Rate Cases" herein and Note 13 to the financial statements under "Recently Issued Accounting Standards""Regulatory Matters – Base Rate Cases" for additional information. |
| |
(b) | The authorized ROE range for Atlanta Gas Light, Virginia Natural Gas, and Florida City Gas was 10.55% - 10.95%, 9.00% - 10.00%, and 10.25% - 12.25%, respectively, at December 31, 2017. |
| |
(c) | Plant nameplate capacity ratings include 100%Regulatory mechanisms that allow recovery of all solar facilities. When taking into considerationcosts in the Company's 90% equity interest in STRevent of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and 51% equity interest in SRP, the Company's equity portion of total nameplate capacity for 2015customer consumption. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is 9,595 MW.warmer than normal and decreasing amounts charged when weather is colder than normal. |
| |
(d) | BeginningRecovery of fixed customer service costs separately from assumed natural gas volumes used by customers. |
| |
(e) | Programs that update or expand distribution systems and LNG facilities. |
| |
(f) | The recovery (refund) of bad debt expense over (under) an established benchmark expense. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms. |
| |
(g) | Recovery of costs associated with plans to achieve specified energy savings goals. |
| |
(h) | See "Base Rate Cases" herein and Note 3 to the financial statements under "Regulatory Matters – Base Rate Cases" for additional information. |
Infrastructure Replacement Programs and Capital Projects
The Company continues to focus on capital discipline and cost control while pursuing projects and initiatives that are expected to have current and future benefits to customers, provide an appropriate return on invested capital, and help ensure the safety and reliability of the utility infrastructure.Total capital expenditures incurred during 2017 for gas distribution operations were $1.3 billion. The following table and discussions provide updates on the infrastructure replacement programs at the natural gas distribution utilities, which are designed to update or expand the Company's distribution systems to improve reliability and meet operational flexibility and growth. The anticipated expenditures for these programs in 2018 are quantified in the discussion below.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
Utility | | Program | | Program Details | | Recovery | | Expenditures in 2017 | | Expenditures Since Project Inception | | Miles of Pipe Installed Since Project Inception | | Scope of Program | | Program Duration | | Last Year of Program |
| | | | | | | | (in millions) | | | | (miles) | | (years) | | |
Nicor Gas | | Investing in Illinois | | (a)(b) | | Rider | | $ | 336 |
| | $ | 907 |
| | 516 |
| | 800 |
| | 9 |
| | 2023 |
Atlanta Gas Light | | Integrated Vintage Plastic Replacement Program (i-VPR) | | (c)(i) | | Base Rates | | 50 |
| | 251 |
| | 782 |
| | 756 |
| | 4 |
| | 2017 |
Atlanta Gas Light | | Integrated System Reinforcement Program (i-SRP) | | (g)(i) | | Base Rates | | 76 |
| | 446 |
| | n/a |
| | n/a |
| | 8 |
| | 2017 |
Atlanta Gas Light | | Integrated Customer Growth Program (i-CGP) | | (h)(i) | | Base Rates | | 18 |
| | 89 |
| | n/a |
| | n/a |
| | 8 |
| | 2017 |
Chattanooga Gas | | Bare Steel & Cast Iron | | (e) | | Base Rates | | 3 |
| | 43 |
| | 94 |
| | 111 |
| | 10 |
| | 2020 |
Florida City Gas | | Safety, Access and Facility Enhancement Program (SAFE) | | (d) | | Rider | | 10 |
| | 21 |
| | 64 |
| | 250 |
| | 10 |
| | 2025 |
Florida City Gas | | Galvanized Replacement Program | | (f) | | Base Rates | | — |
| | 16 |
| | 80 |
| | 111 |
| | 17 |
| | 2017 |
Virginia Natural Gas | | Steps to Advance Virginia's Energy (SAVE and SAVE II) | | (a) | | Rider | | 34 |
| | 156 |
| | 255 |
| | 496 |
| | 10 |
| | 2021 |
Elizabethtown Gas | | Aging Infrastructure Replacement (AIR) | | (e) | | Base Rates | | 16 |
| | 115 |
| | 96 |
| | 130 |
| | 4 |
| | 2017 |
Total | | | | | | | | $ | 543 |
| | $ | 2,044 |
| | 1,887 |
| | 2,654 |
| | | | |
| |
(a) | Replacement of cast iron, bare steel, mid-vintage plastic, and risk-based materials. |
| |
(b) | Represents expenditures on qualifying infrastructure placed into service after December 9, 2014. |
| |
(c) | Replacement of early vintage plastic, risk-based mid-vintage plastic, and mid-vintage neighborhood convenience. |
| |
(d) | Replacement of four-inch and smaller mains, associated service lines, and in 2012, plant availability is calculated as a weighted equivalent availability.some instances above-ground facilities associated with rear-lot easements. |
| |
(e) | Replacement of cast iron and bare steel pipes. |
| |
(f) | Replacement of galvanized and X-Tube steel pipes. Reflects expenditures and miles of pipe installed since the Company acquired Florida City Gas in 2004. |
| |
(g) | Installation of large diameter pressure improvement and system reinforcement projects. |
| |
(h) | Installation of new business construction and strategic line extension. |
| |
(i) | Recovery of the related program costs was incorporated in Atlanta Gas Light's petition for GRAM, which the Georgia PSC approved on February 21, 2017. See "Base Rate Cases" herein and Note 3 to the financial statements under "Regulatory Matters – Base Rate Cases" for additional information. |
Nicor Gas
In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, under which Nicor Gas implemented rates that became effective in March 2015. Nicor Gas expects to place into service $350 million of qualifying projects under Investing in Illinois in 2018.
Investing in Illinois is subject to annual review by the Illinois Commission. In conjunction with the base rate case order issued by the Illinois Commission on January 31, 2018, Nicor Gas is recovering the portion of these program costs incurred prior to December 31, 2017 through base rates. See "Base Rate Cases" herein for additional information.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which was initially approved by the Georgia PSC in 2009, is comprised of i-SRP, i-CGP, and i-VPR, and consists of infrastructure development, enhancement, and replacement programs that are used to update and expand distribution systems and LNG facilities, improve system reliability, and meet operational flexibility and growth. For 2017 and subsequent years, the recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
The i-CGP program authorized Atlanta Gas Light to spend $91 million through 2017 on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. This program ended in 2017 and was replaced with a tariff to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
The i-SRP program authorized $445 million of capital spending through 2017 for projects to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, improve its peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its i-SRP seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020.
The i-VPR program authorized Atlanta Gas Light to spend $275 million through 2017 to replace 756 miles of aging plastic pipe that was installed primarily in the mid-1960s to the early 1980s. Atlanta Gas Light has identified approximately 3,300 miles of vintage plastic mains in its system that should be considered for potential replacement.
See "Base Rate Cases" herein for additional information on GRAM.
Elizabethtown Gas
Elizabethtown Gas' 2013 extension of the AIR enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65%. Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See "Base Rate Cases" herein for additional information.
In 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, Elizabethtown Gas withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. Elizabethtown Gas expects to file a revised plan during the second half of 2018. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In 2012, the Virginia Commission approved the SAVE program, an accelerated infrastructure replacement program, to be completed over a five-year period. This program included a maximum allowance for capital expenditures of $25 million per year, not to exceed $105 million in total.
In March 2016, the Virginia Commission approved an extension to the SAVE program for Virginia Natural Gas to replace more than 200 miles of aging pipeline infrastructure and invest up to $30 million in 2016 and up to $35 million annually through 2021. Virginia Natural Gas expects to invest $35 million under this program in 2018.
The SAVE program is subject to annual review by the Virginia Commission. In conjunction with the base rate case order issued by the Virginia Commission on December 21, 2017, Virginia Natural Gas is recovering the portion of these program costs incurred prior to September 1, 2017 through base rates. See "Base Rate Cases" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Florida City Gas
In 2015, the Florida PSC approved Florida City Gas' SAFE, under which costs incurred for replacing aging pipes are recovered through a rate rider with annual adjustments and true-ups. Under the program, Florida City Gas is authorized to spend $105 million over a 10-year period on infrastructure relocation and enhancement projects. Florida City Gas expects to invest $10 million under this program in 2018.
PRP Settlement
In 2015, Atlanta Gas Light received a final order from the Georgia PSC for a rate true-up of allowed unrecovered revenue through 2014 related to its PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million previously unrecovered program revenue. The remaining $34 million requested related primarily to previously unrecognized ratemaking amounts and did not have a material impact on the Company's financial statements. The Company also recognized $1 million of interest expense and $5 million in operations and maintenance expense related to the PRP on the Company's statements of income for the predecessor year ended December 31, 2015. See "Unrecognized Ratemaking Amounts" herein for additional information.
As a result of the PRP settlement, Atlanta Gas Light began recovering incremental PRP surcharge amounts through three phased in increases in addition to its already existing PRP surcharge amount, which was established to address recovery of the unrecovered PRP balance of $144 million in 2015 and the estimated amounts to be earned under the program through 2025. The initial incremental surcharge of approximately $15 million annually was effective in October 2015, with additional annual increases of approximately $15 million in each of October 2016 and 2017. The final increase scheduled for October 2017 was included in the implementation of GRAM in March 2017. The under recovered balance is the result of the continued revenue requirement earned under the program offset by the existing and incremental PRP surcharges. The unrecovered balance at December 31, 2017 was $187 million, including $104 million of unrecognized equity return. The PRP surcharge will remain in effect until the earlier of the full recovery of the under recovered amount or December 31, 2025. See "Base Rate Cases" herein for additional information on GRAM.
One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs will be included in future base rates in 2018. Provisions in the order resulted in the recognition of $5 million in operations and maintenance expense for the predecessor year ended December 31, 2015 on the Company's statements of income. In 2017, Atlanta Gas Light recovered $20 million from the settlement of contractor litigation claims and continues to pursue contractual and legal claims against a third-party contractor. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. The ultimate outcome of this matter cannot be determined at this time.
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved GRAM and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, using an earnings band based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Atlanta Gas Light adjusts rates up to the lower end of the band of 10.55% and adjusts rates down to the higher end of the band of 10.95%. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include i-VPR and i-SRP, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the i-CGP that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the proposed sale of Elizabethtown Gas.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
On December 21, 2017, the Virginia Commission approved a settlement for a $34 million increase in annual base rate revenues, effective September 1, 2017, including $13 million related to the recovery of investments under the SAVE program. See "Infrastructure Replacement Programs and Capital Projects" herein for additional information. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates.
On January 31, 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective February 8, 2018, based on a ROE of 9.8%.
Pending Base Rate Cases
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. On January 29, 2018, Florida City Gas filed an update to incorporate the effects of the Tax Reform Legislation that, if approved, would reduce the requested base rate revenues by $4 million. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under SAFE that are currently being recovered through a surcharge. Additionally, Florida City Gas requested an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission requesting a $7 million increase in annual base rate revenues. The requested increase, which incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee Public Utility Commission is expected to rule on the requested increase in the third quarter 2018.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Other
The New Jersey BPU, Virginia Commission, Tennessee Public Utility Commission, and Maryland PSC each issued an order effective January 1, 2018 that requires utilities in their respective states to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. The New Jersey BPU's order requires Elizabethtown Gas to file by March 2, 2018 proposed revised base rates with an April 1, 2018 interim effective date and a July 1, 2018 final effective date. Virginia Natural Gas will address the Virginia Commission's order in its Annual Information Filing, which will be filed by July 1, 2018. The Tennessee Public Utility Commission's order required Chattanooga Gas to file proposals to reduce rates or make other ratemaking adjustments to account for the impact of the Tax Reform Legislation. Chattanooga Gas made the required filing as part of its February 15, 2018 general base rate case filing. The Maryland PSC's order required Elkton Gas to file an explanation of the impact of the Tax Reform Legislation on its expenses and revenues, as well as when and how it expects to pass through to its customers those effects. Elkton Gas made the required filing on February 15, 2018 and will reduce annual base rates by $0.1 million effective April 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018.
The Illinois Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
Asset Management Agreements
All of the natural gas distribution utilities except Nicor Gas use asset management agreements with the Company's wholly-owned subsidiary, Sequent, for the primary purpose of reducing utility customers' gas cost recovery rates through payments to the utilities by Sequent. For Atlanta Gas Light, these payments are controlled by the Georgia PSC and are utilized for infrastructure improvements and to fund heating assistance programs, rather than as a reduction to gas cost recovery rates. Under these asset management agreements, Sequent supplies natural gas to the utility and markets available pipeline and storage capacity to improve the overall cost of supplying gas to the utility customers. Currently, the Company's utilities primarily purchase their gas
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
from Sequent. The purchase agreements require Sequent to provide firm gas to the natural gas distribution utilities, but these natural gas distribution utilities maintain the right and ability to make their own long-term supply arrangements if they believe it is in the best interest of their customers.
Each agreement provides for Sequent to make payments to the natural gas distribution utilities through either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without an annual minimum guarantee, or a fixed fee. From the inception of these agreements in 2001 through December 31, 2017, Sequent made sharing payments to the natural gas distribution utilities under these agreements totaling $390 million.
The following table provides payments made by Sequent to the natural gas distribution utilities under these agreements during the last three years:
|
| | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | |
| | Total Amount Received | | | Total Amount Received | |
| | Year Ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | Year Ended December 31, | |
| | 2017 | | 2016 | | | 2016 | | 2015 | | Expiration Date |
| | (in millions) | | | (in millions) | |
Elizabethtown Gas | | $ | 11 |
| | $ | 3 |
| | | $ | 12 |
| | $ | 28 |
| | March 2019 |
Virginia Natural Gas | | 6 |
| | 2 |
| | | 9 |
| | 15 |
| | March 2019 |
Atlanta Gas Light | | 4 |
| | 1 |
| | | 6 |
| | 15 |
| | March 2020 |
Florida City Gas | | 1 |
| | — |
| | | 1 |
| | 1 |
| | (a) |
Chattanooga Gas | | 1 |
| | — |
| | | 1 |
| | 1 |
| | March 2021 |
Total(b) | | $ | 23 |
| | $ | 6 |
| | | $ | 29 |
| | $ | 60 |
| | |
| |
(a) | The agreement renews automatically each year unless terminated by either party. |
| |
(b) | Payments made to Elkton Gas were less than $1 million for each of the periods presented. |
Upon consummation of the asset sales of Elizabethtown Gas and Elkton Gas, South Jersey Industries, Inc. will assume the asset management agreements of Elizabethtown Gas and Elkton Gas. See Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information on these sales.
energySMART
In 2014, the Illinois Commission approved Nicor Gas' energySMART through 2017, which outlined energy efficiency program offerings and therm reduction goals, and subsequently extended the program to 2021. Through December 31, 2017, Nicor Gas spent $107 million of the initial authorized expenditure of $113 million. A new four-year program began on January 1, 2018, with an additional authorized expenditure of $160 million. Nicor Gas expects to invest $40 million under this program in 2018.
Unrecognized Ratemaking Amounts
The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.
|
| | | | | | | |
| December 31, 2017 | | December 31, 2016 |
| (in millions) |
Atlanta Gas Light | $ | 104 |
| | $ | 110 |
|
Virginia Natural Gas | 11 |
| | 11 |
|
Elizabethtown Gas(*) | 8 |
| | 6 |
|
Nicor Gas | 2 |
| | 2 |
|
Total | $ | 125 |
| | $ | 129 |
|
| |
(*) | See Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the pending asset sale. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Income Tax Matters
Federal Tax Reform Legislation
On December 22, 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduces the federal corporate income tax rate to 21%, retains normalization provisions for public utility property and existing renewable energy incentives, and repeals the corporate alternative minimum tax.
For businesses other than regulated utilities, the Tax Reform Legislation allows 100% bonus depreciation of qualified property acquired and placed in service between September 28, 2017 and January 1, 2023 and phases down by 20% each year until completely phased out for qualified property placed in service after December 31, 2027. Further, the business interest deduction is limited to 30% of taxable income excluding interest, net operating loss (NOL) carryforwards, and depreciation and amortization through December 31, 2021 and thereafter to 30% of taxable income excluding interest and NOL carryforwards.
Regulated utility businesses, including the natural gas distribution companies, can continue deducting all business interest expense and are not eligible for bonus depreciation on capital assets acquired and placed in service after September 27, 2017. Projects with binding contracts before September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the Protecting Americans from Tax Hikes (PATH) Act.
In addition, under the the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year.
For the year ended December 31, 2017, implementation of the Tax Reform Legislation resulted in an estimated net tax expense of $93 million and a $777 million increase in regulatory liabilities, primarily due to the impact of the reduction of the corporate income tax rate on deferred tax assets and liabilities.
The Tax Reform Legislation is subject to further interpretation and guidance from the IRS, as well as each respective state's adoption. In addition, the regulatory treatment of certain impacts of Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies as further described in Note 3 to the financial statements under "Base Rate Cases" and "Other" for additional information.
See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Bonus Depreciation
Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $200 million for the 2017 tax year and approximately $60 million for the 2018 tax year. Should Southern Company have a NOL in 2018, all of these cash flows may not be fully realized in 2018. See Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.
State Tax Reform Legislation
On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required the Company to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, of which $15 million was expensed and $9 million was recorded as a regulatory asset.
Change in State Apportionment Factors
Southern Company calculated new apportionment factors in several states to include the Company in its consolidated tax filings, which resulted in $22 million of additional deferred income tax expenses in the successor year ended December 31, 2017.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Other Matters
The Company is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, the Company is subject to certain claims and legal actions arising in the ordinary course of business.
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of the Company, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and the Company's motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on the Company's financial statements.
The Company is assessing its alleged involvement in an incident that occurred in one of its service territories that resulted in several deaths, injuries, and property damage. One of the natural gas distribution utilities has been named as one of the defendants in several lawsuits related to this incident. The Company has insurance that provides full coverage of any financial exposure in excess of $11 million per incident. During the successor period ended December 31, 2016 and the predecessor period ended December 31, 2015, the Company recorded reserves for substantially all of its potential exposure from these cases.
The ultimate outcome of these matters and such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. See Note 3 to the financial statements under "General Litigation Matters" for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The Company owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day. It is expected to be operational in the first half of 2018. The ultimate outcome of this matter cannot be determined at this time.
A wholly-owned subsidiary of the Company owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in the Company retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. The Company intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with the Company's annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on the Company's financial statements.
Effective January 1, 2018, the Company conformed its paid time off policy to align with Southern Company. Under the new policy, paid time off days are vested by the employee on the first day of each year and will continue to be recovered through rates on an as-paid basis. As a result, the Company accrued $21 million as of January 1, 2018, of which $9 million was recorded as a regulatory asset.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Company prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.
Utility Regulation
The natural gas distribution utilities comprised approximately 82% of the Company's total operating revenues for 2017 and are subject to rate regulation by their respective state regulatory agencies, which set the rates utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards has a further effect on the Company's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on the Company's results of operations and financial condition than they would on a non-regulated company.
As reflected in Note 1 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the Company's financial statements.
Accounting for Income Taxes
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the many states in which the Company operates.
On behalf of the Company, Southern Company files a consolidated federal income tax return and various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of the Company's, as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.
Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined or unitary filing methodology is required. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the Company's financial statements.
Given the significant judgment involved in estimating NOL carryforwards and tax credit carryforwards and multi-state apportionments, the Company considers state deferred income tax liabilities and assets to be critical accounting estimates.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory liabilities cannot be determined at this time. See "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 3 to the financial statements under "Base Rate Cases" and "Other" and Note 5 to the financial statements under "Current and Deferred Income Taxes" for additional information.
Assessment of Assets
Goodwill
The Company does not amortize its goodwill, but tests it annually for impairment at the reporting unit level during the fourth quarter or more frequently if impairment indicators arise. These indicators include, but are not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics.
As part of the Company's impairment test, the Company may perform an initial qualitative Step 0 assessment to determine whether it is more likely than not that the fair value of each reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If the Company elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the Company determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it performs the two-step goodwill impairment test.
Step 1 of the two-step goodwill impairment test compares the fair value of the reporting unit to its carrying value. If the result of the Step 1 test reveals that the estimated fair value is below its carrying value, the Company proceeds with Step 2.
Step 2 of the two-step goodwill impairment test compares the implied fair value of goodwill, which is calculated as the residual amount from the reporting unit's overall fair value after assigning fair values to its assets and liabilities under a hypothetical purchase price allocation as if the reporting unit had been acquired in a business combination, to its carrying value. Based on the result of the Step 2 test, the Company records a goodwill impairment charge for any excess of carrying value over the implied fair value of goodwill.
For the 2017 annual impairment test, the Company performed Step 1 of the two-step impairment test, which resulted in the fair value of all of its reporting units that have goodwill exceeding their carrying value. For the 2016 and 2015 annual impairment tests, the Company performed the qualitative Step 0 assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative analysis was required. In the third quarter 2015, the Company identified potential impairment indicators and performed an interim impairment test for its storage and fuels reporting unit, which resulted in impairment of the full $14 million goodwill balance for that reporting unit.
As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the Company considers these estimates to be critical accounting estimates.
See "Recently Issued Accounting Standards – Other" herein for information on the Company's adoption of ASU No. 2017-04 effective January 1, 2018.
Long-Lived Assets
The Company depreciates or amortizes its long-lived and intangible assets over their estimated useful lives. The Company assesses its long-lived and intangible assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. When such events or circumstances are present, the Company assesses the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. Impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, the Company records an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.
As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the Company considers these estimates to be critical accounting estimates.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Derivatives and Hedging Activities
Determining whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is voluminous and complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in the Company's assessment of the likelihood of future hedged transactions, or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the accounting treatment.
Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on the balance sheets as either assets or liabilities measured at their fair value. If the transaction qualifies for, and is designated as, a normal purchase or normal sale, it is exempted from fair value accounting treatment and is, instead, subject to traditional accrual accounting. The Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.
Changes in the derivatives' fair value are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are recorded in OCI on the balance sheets until the hedged transaction affects earnings in the case of a cash flow hedge. Additionally, a company is required to formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment.
Nicor Gas and Elizabethtown Gas utilize derivative instruments to hedge the price risk for the purchase of natural gas for customers. These derivatives are reflected at fair value and are not designated as accounting hedges. Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers, subject to review by the applicable state regulatory agencies, and therefore have no direct impact on earnings. Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities.
The Company uses derivative instruments primarily to reduce the impact to its results of operations due to the risk of changes in the price of natural gas and to a lesser extent the Company hedges against warmer-than-normal weather and interest rates. The fair value of natural gas derivative instruments used to manage exposure to changing natural gas prices reflects the estimated amounts that the Company would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. For derivatives utilized at gas marketing services and wholesale gas services that are not designated as accounting hedges, changes in fair value are reported as gains or losses in the Company's results of operations in the period of change. Gas marketing services records derivative gains or losses arising from cash flow hedges in OCI and reclassifies them into earnings in the same period that the underlying hedged item is recognized in earnings.
The Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:
the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);
events specific to a given counterparty; and
the impact of the Company's nonperformance risk on its liabilities.
If there is a significant change in the underlying market prices or pricing assumptions the Company uses in pricing its derivative assets or liabilities, the Company may experience a significant impact on its financial position, results of operations, and cash flows. See Note 10 to the financial statements for additional information.
Given the assumptions used in pricing the derivative asset or liability, the Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.
Pension and Other Postretirement Benefits
The Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefits costs and obligations.
Key elements in determining the Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on the Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. The Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to the Company's target asset allocation. For purposes of determining its liability related to the pension and other postretirement benefit plans, the Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. Prior to 2016, the Company computed the interest cost component of its net periodic pension and other postretirement benefit plan expense using the same single-point discount rate. In 2016, the Company adopted a full yield curve approach for calculating the interest cost component whereby the discount rate for each year is applied to the liability for that specific year. As a result, the interest cost component of net periodic pension and other postretirement benefit plan expense decreased by approximately $7 million in 2016.
A 25 basis point change in any significant assumption (discount rate, salaries, or long-term return on plan assets) would result in a $2 million or less change in total annual benefit expense and a $42 million or less change in projected obligations.
See Note 2 to the financial statements for additional information regarding pension and other postretirement benefits.
Contingent Obligations
The Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Note 3 to the financial statements for more information regarding certain of these contingencies. The Company periodically evaluates its exposure to such risks and records reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the Company's results of operations, cash flows, or financial condition.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements.
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to real estate and fleet vehicles where the Company is the lessee and to natural gas home appliances where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. The Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
FINANCIAL CONDITION AND LIQUIDITY
Overview
The Company's financial condition remained stable at December 31, 2017. The Company's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations. Operating cash flows provide a substantial portion of the Company's cash needs. For the three-year period from 2018 through 2020, the Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. The Company plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, equity contributions from Southern Company, and borrowings from financial institutions and with proceeds from the pending asset sales of Elizabethtown Gas and Elkton Gas. The Company plans to use commercial paper to manage seasonal variations in operating cash flows and other working capital needs. The Company intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. The New Jersey BPU restricts the amount Elizabethtown Gas can dividend to its parent company to 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, the Company is prohibited from paying dividends to its parent company, Southern Company, if the Company's senior unsecured debt rating falls below investment grade. At December 31, 2017, the amount of subsidiary retained earnings and net income restricted to dividend totaled $719 million. These restrictions did not have any impact on the Company's ability to meet its cash obligations, nor does management expect such restrictions to materially impact the Company's ability to meet its currently anticipated cash obligations.
The Company's investments in the qualified pension plan increased in value at December 31, 2017 as compared to December 31, 2016. There were no voluntary contributions to the qualified pension plan in 2017 and no mandatory contributions to its qualified pension plan are anticipated during 2018. See Note 2 to the financial statements for additional information.
Net cash provided from operating activities totaled $883 million for 2017, primarily due to earnings and the timing of cash receipts for the sale of natural gas inventory and vendor payments. Net cash used for operating activities was $328 million for the successor period of July 1, 2016 through December 31, 2016, primarily due to a $125 million voluntary pension contribution, a $35 million payment for the settlement of an interest rate swap, and less cash due to the timing of collecting receivables and disbursing payables. Due to the seasonal nature of its business, the Company typically reports negative cash flows from operating activities in the second half of the year. Net cash provided from operating activities was $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016, primarily due to low volumes of natural gas sales and changes in natural gas inventory as a result of warmer weather and the timing of recovery of related gas costs and weather normalization adjustments from customers. Net cash provided from operating activities was $1.4 billion for the predecessor year ended December 31, 2015, primarily due to the timing of recovery of related gas costs from customers, cash provided from derivative financial instrument assets and liabilities, and a tax refund of $150 million related to the extension of bonus depreciation.
Net cash used for investing activities totaled $1.6 billion for 2017, which reflected $1.5 billion in capital expenditures primarily due to gross property additions for infrastructure replacement programs at gas distribution operations and $145 million in capital contributions to equity method investments in pipeline projects, partially offset by $80 million in returned capital from equity method investments in pipeline projects. Net cash used for investing activities was $2.1 billion for the successor period of July 1, 2016 through December 31, 2016, which reflected $1.4 billion primarily related to the Company's acquisition of the 50% interest in SNG, and $632 million in capital expenditures. Net cash used for investing activities was $559 million and $1.0 billion for the predecessor period of January 1, 2016 through June 30, 2016 and the predecessor year ended December 31, 2015, respectively, which primarily related to capital expenditures. See Note 4 to the financial statements under "Equity Method Investments – SNG" and Note 11 to the financial statements under "Investment in SNG" for additional information.
Net cash provided from financing activities totaled $741 million for 2017, primarily due to $850 million in debt issuances, $262 million in net additional commercial paper borrowings, and $103 million in capital contributions from Southern Company, partially offset by $443 million in common stock dividend payments to Southern Company and $22 million in repayment of long-term debt. Net cash provided from financing activities was $2.4 billion for the successor period of July 1, 2016 through December 31, 2016, which reflected $1.1 billion of capital contributions from Southern Company, primarily used to fund the
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Company's investment in SNG, $1.1 billion in net additional commercial paper borrowings, partially offset by $160 million for the purchase of the 15% noncontrolling ownership interest in SouthStar, and $900 million in proceeds from debt issuances, partially offset by $420 million in debt payments. Net cash used for financing activities was $558 million for the predecessor period of January 1, 2016 through June 30, 2016, primarily due to $896 million in net repayment of commercial paper borrowings and $125 million in repayment of long-term debt, partially offset by $600 million in debt issuances. Net cash used for financing activities was $366 million for the predecessor year ended December 31, 2015, primarily due to the net repayment of commercial paper borrowings, partially offset by the proceeds from debt issuances in excess of debt repayments. See Note 4 to the financial statements under "Variable Interest Entities" and "Equity Method Investments – SNG" and Note 11 to the financial statements under "Investment in SNG" for additional information.
Significant balance sheet changes at December 31, 2017 include an increase of $1.2 billion in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase of $1.0 billion in deferred credits related to income taxes primarily resulting from the impacts of the Tax Reform Legislation, a decrease of $886 million in accumulated deferred income tax liabilities primarily due to the change in the federal corporate income tax rate, partially offset by tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and an increase in long-term debt of $632 million, primarily due to $450 million of senior notes issued in May 2017 and $200 million of first mortgage bonds at Nicor Gas issued in each of August 2017 and November 2017. Other significant balance sheet changes include an increase of $261 million in notes payable primarily related to an increase in commercial paper borrowings of $510 million at Southern Company Gas Capital, partially offset by a decrease in commercial paper borrowings of $249 million at Nicor Gas. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Notes 5 and 6 to the financial statements for additional information.
Sources of Capital
The Company plans to obtain the funds to meet its future capital needs through operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, the Company plans to utilize the proceeds from the pending asset sales of Elizabethtown Gas and Elkton Gas to pay the income taxes resulting from the sales, to retire existing debt, and for general corporate purposes. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission.
The Southern Company system does not maintain a centralized cash or money pool. Therefore, except as described below, funds of the Company are not commingled with funds of any other company in the Southern Company system. The Company obtains financing separately without credit support from any affiliate in the Southern Company system. See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
The Company maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas that consist of short-term, unsecured promissory notes. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the Company's other subsidiaries benefit from Southern Company Gas Capital's commercial paper program.
At December 31, 2017, the Company's current liabilities exceeded current assets by $1.0 billion, primarily as a result of $1.5 billion in notes payable. The Company's current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. The Company intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, equity contributions from Southern Company, and the proceeds from the pending asset sales of Elizabethtown Gas and Elkton Gas to fund short-term capital needs. The Company has substantial cash flow from operating activities and access to capital markets and financial institutions to meet liquidity needs.
At December 31, 2017, the Company had $73 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2017 were as follows:
|
| | | | | | | | |
Company | | Expires 2022 | | Unused |
| | (millions) |
Southern Company Gas Capital(*) | | $ | 1,400 |
| | $ | 1,390 |
|
Nicor Gas | | 500 |
| | 500 |
|
Total | | $ | 1,900 |
| | $ | 1,890 |
|
(*)The Company guarantees the obligations of Southern Company Gas Capital.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
See Note 6 to the financial statements under "Bank Credit Arrangements" for additional information.
In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.4 billion and $500 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of the Company and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if the Company or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to the Company.
The Company makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | Short-term Debt at the End of the Period | | Short-term Debt During the Period(*) |
| | Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) | | | | (in millions) |
Successor – December 31, 2017: | | | | | | | | | | |
Southern Company Gas Capital | | $ | 1,243 |
| | 1.73 | % | | $ | 723 |
| | 1.40 | % | | $ | 1,243 |
|
Nicor Gas | | 275 |
| | 1.83 | % | | 176 |
| | 1.12 | % | | 525 |
|
Total | | $ | 1,518 |
| | 1.75 | % | | $ | 899 |
| | 1.35 | % | | |
| | | | | | | | | | |
Successor – December 31, 2016: | | | | | | | | | | |
Southern Company Gas Capital | | $ | 733 |
| | 1.09 | % | | $ | 461 |
| | 0.79 | % | | $ | 770 |
|
Nicor Gas | | 524 |
| | 0.95 | % | | 309 |
| | 0.67 | % | | 587 |
|
Total | | $ | 1,257 |
| | 1.03 | % | | $ | 770 |
| | 0.74 | % | | |
| | | | | | | | | | |
Predecessor – December 31, 2015: | | | | | | | | | | |
Southern Company Gas Capital | | $ | 471 |
| | 0.71 | % | | $ | 382 |
| | 0.49 | % | | $ | 787 |
|
Nicor Gas | | 539 |
| | 0.52 | % | | 349 |
| | 0.38 | % | | 585 |
|
Total | | $ | 1,010 |
| | 0.60 | % | | $ | 731 |
| | 0.44 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the 12-month periods. |
The Company believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued. The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale.
Financing Activities
The long-term debt on the Company's balance sheets includes both principal and non-principal components. As of December 31, 2017, the non-principal components totaled $508 million, including the amount attributable to long-term debt
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
due within one year, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In December 2016, the Company executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow the Company to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes.
In July 2017, Atlanta Gas Light repaid at maturity $22 million of Series C medium-term notes.
On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.
On January 4, 2018, the Company issued a floating rate promissory note to Southern Company, in an aggregate principal amount of $100 million due July 31, 2018 bearing interest based on one-month LIBOR, to support the current activities of wholesale gas services.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Credit Rating Risk
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at December 31, 2017 was $10 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Company to access capital markets and would be likely to impact the cost at which it does so.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the Company, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
While it is unclear how the credit rating agencies and the relevant state regulatory bodies may respond to the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including the Company, may be negatively impacted. Absent actions by Southern Company and its subsidiaries, including the Company, to mitigate the resulting impacts, which, among other alternatives, could include adjusting capital structure and/or monetizing regulatory assets, the Company's, Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. See Note 3 to the financial statements for additional information.
Market Price Risk
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of the Company that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. To manage the volatility attributable to these exposures, the Company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company uses derivatives to buy and sell natural gas as well as for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
To mitigate future exposure to changes in interest rates, the Company may enter into derivatives designated as hedges. The weighted average interest rate on $200 million of long-term variable interest rate exposure at December 31, 2017 was 1.71%. If the Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would have an immaterial effect on annualized interest expense at December 31, 2017. See Note 1 to the financial statements under "Financial Instruments" and Note 10 to the financial statements for additional information.
Certain natural gas distribution utilities of the Company manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, the Company has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower adjusted operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter (OTC) energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Gas marketing services and wholesale gas services also actively manage storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining operating margins. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The Company had no material change in market risk exposure for the year ended December 31, 2017 when compared to the year ended December 31, 2016.
For the periods presented below, the changes in net fair value of derivative contracts were as follows:
|
| | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2017 | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | Year Ended December 31, 2015 |
| (in millions) | | | (in millions) |
Contracts outstanding at beginning of period, assets (liabilities), net | $ | 8 |
| $ | (54 | ) | | | $ | 75 |
| $ | 61 |
|
Contracts realized or otherwise settled | (1 | ) | 18 |
| | | (77 | ) | (17 | ) |
Current period changes(a) | (113 | ) | 48 |
| | | (82 | ) | 32 |
|
Contracts outstanding at end of period, assets (liabilities), net | (106 | ) | 12 |
| | | (84 | ) | 76 |
|
Netting of cash collateral | 193 |
| 62 |
| | | 120 |
| 96 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 87 |
| $ | 74 |
| | | $ | 36 |
| $ | 172 |
|
| |
(a) | Current period changes also include the changes in fair value of new contracts entered into during the period, if any. |
| |
(b) | Net fair value of derivative contracts outstanding excludes premium and intrinsic value associated with weather derivatives of $11 million at December 31, 2017 and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016, $5 million at June 30, 2016, and $10 million at December 31, 2015. |
The net hedge volume of energy-related derivative contracts for natural gas positions for the years ended December 31 were as follows:
|
| | | | | | |
| | 2017 | | 2016 |
| | mmBtu Volume |
| | (in millions) |
Commodity – Natural gas | | 300 |
| | 157 |
|
Net Purchased/(Sold) Volume | | 300 |
| | 157 |
|
The Company's derivative contracts are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. The volume presented above represents the net of long natural gas positions of 3.51 billion mmBtu and short natural gas positions of 3.21 billion mmBtu at December 31, 2017 and the net of long natural gas positions of 3.31 billion mmBtu and short natural gas positions of 3.16 billion mmBtu at December 31, 2016.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Energy-related derivative contracts that are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in cost of natural gas as the underlying gas is used in operations and ultimately recovered through the respective cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales), are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
The Company uses OTC contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. See Note 9 to the financial statements for further discussion of fair value measurements.
The maturities of the energy-related derivative contracts at December 31, 2017 were as follows: |
| | | | | | | | | | | | | | | |
| | | Fair Value Measurements |
| | | December 31, 2017 |
| | | Maturity |
| Total Fair Value | | Year 1 | | Years 2 & 3 | | Years 4 & 5 |
| (in millions) |
Level 1(a) | $ | (148 | ) | | $ | (71 | ) | | $ | (59 | ) | | $ | (18 | ) |
Level 2(b) | 42 |
| | 10 |
| | 30 |
| | 2 |
|
Fair value of contracts outstanding at end of period(c) | $ | (106 | ) | | $ | (61 | ) | | $ | (29 | ) | | $ | (16 | ) |
| |
(a) | Valued using NYMEX futures prices. |
| |
(b) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
| |
(c) | Excludes cash collateral of $193 million as well as premium and associated intrinsic value associated with weather derivatives of $11 million at December 31, 2017. |
Value at Risk (VaR)
VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. The Company's VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. The Company's VaR is determined on a 95% confidence interval and a one-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of the Company is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because the Company generally manages physical gas assets and economically protects its positions by hedging in the futures markets, the Company's open exposure is generally mitigated. The Company employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.
The Company actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a one-day holding period, SouthStar's portfolio of positions for all periods presented was immaterial.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
For the periods presented below, wholesale gas services had the following VaRs:
|
| | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year Ended December 31, 2017 | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | Year Ended December 31, 2015 |
| (in millions) | | | (in millions) |
Period end(*) | $ | 4.8 |
| $ | 2.3 |
| | | $ | 1.9 |
| $ | 2.4 |
|
Average | 2.0 |
| 2.0 |
| | | 2.0 |
| 3.0 |
|
High(*) | 4.8 |
| 2.8 |
| | | 2.5 |
| 7.3 |
|
Low | 1.0 |
| 1.4 |
| | | 1.6 |
| 1.6 |
|
| |
(*) | Increase in VaR at December 31, 2017 was driven by significant natural gas price increases in Sequent's key markets due to colder-than-normal weather. As weather moderated during January 2018, VaR reduced to a level consistent with prior periods. |
Credit Risk
Gas Distribution Operations
Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2017, the four largest Marketers based on customer count accounted for 19% of the Company's adjusted operating margin and 22% of gas distribution operations' adjusted operating margin.
Several factors are designed to mitigate the Company's risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. On a monthly basis, the Risk Management Committee reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. The Company believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.
Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.
Gas Marketing Services
The Company obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed the Company's credit threshold. The Company considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, the Company also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements.
Wholesale Gas Services
The Company has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company's credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The Company may require counterparties to pledge additional collateral when deemed necessary. The Company conducts credit evaluations and obtains appropriate internal approvals for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, the Company requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Certain of the Company's derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral it posts in the normal course of business when its financial instruments are in net liability positions. At December 31, 2017, for agreements with such features, the Company's derivative instruments with liability fair values totaled $1 million for which the Company had no collateral posted with derivatives counterparties to satisfy these arrangements.
The Company has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2017, wholesale gas services' top 20 counterparties represented approximately 48%, or $203 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody's ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being D / Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties' exposures, and this numeric value is then converted to an S&P equivalent.
The following table provides credit risk information related to the Company's third-party natural gas contracts receivable and payable positions at December 31:
|
| | | | | | | | | | | | | | | |
| Gross Receivables | | Gross Payables |
| 2017 | | 2016 | | 2017 | | 2016 |
| (in millions) | | (in millions) |
Netting agreements in place: | | | | | | | |
Counterparty is investment grade | $ | 342 |
| | $ | 375 |
| | $ | 202 |
| | $ | 227 |
|
Counterparty is non-investment grade | 20 |
| | 14 |
| | 25 |
| | 31 |
|
Counterparty has no external rating | 226 |
| | 223 |
| | 315 |
| | 339 |
|
No netting agreements in place: | | | | | | | |
Counterparty is investment grade | 19 |
| | 11 |
| | 4 |
| | — |
|
Amount recorded in balance sheets | $ | 607 |
| | $ | 623 |
| | $ | 546 |
| | $ | 597 |
|
Capital Requirements and Contractual Obligations
The Company's capital investments are currently estimated to total $1.7 billion for 2018, $1.7 billion for 2019, $1.5 billion for 2020, $1.2 billion for 2021, and $1.4 billion for 2022. The Company's capital investments include estimated capital expenditures related to Elizabethtown Gas and Elkton Gas of $123 million for 2018, $125 million for 2019, $124 million for 2020, $126 million for 2021, and $129 million for 2022. See Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information. The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory agency approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
In addition, as discussed in Note 2 to the financial statements, the Company provides postretirement benefits to certain eligible employees and funds trusts to the extent required by the applicable state regulatory agencies.
Other funding requirements related to obligations associated with scheduled maturities of long-term debt, including the related interest; pipeline charges, storage capacity, and gas supply; operating leases; asset management agreements; financial derivative obligations; pension and other postretirement benefit plans; and other purchase commitments, primarily related to environmental remediation liabilities, are detailed in the contractual obligations table that follows. See Notes 3, 6, 7, and 11 to the financial statements for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Contractual Obligations
Contractual obligations at December 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019- 2020 | | 2021- 2022 | | After 2022 | | Total |
| (in millions) |
Long-term debt(a) — | | | | | | | | | |
Principal | $ | 155 |
| | $ | 350 |
| | $ | 423 |
| | $ | 4,612 |
| | $ | 5,540 |
|
Interest | 241 |
| | 452 |
| | 421 |
| | 3,137 |
| | 4,251 |
|
Pipeline charges, storage capacity, and gas supply(b) | 813 |
| | 968 |
| | 714 |
| | 2,294 |
| | 4,789 |
|
Operating leases(c) | 17 |
| | 32 |
| | 28 |
| | 26 |
| | 103 |
|
Asset management agreements(d) | 9 |
| | 6 |
| | — |
| | — |
| | 15 |
|
Financial derivative obligations(e) | 444 |
| | 174 |
| | 37 |
| | 5 |
| | 660 |
|
Pension and other postretirement benefit plans(f) | 13 |
| | 28 |
| | — |
| | — |
| | 41 |
|
Purchase commitments — | | | | | | | | | |
Capital(g) | 1,821 |
| | 2,979 |
| | 2,662 |
| | — |
| | 7,462 |
|
Other(h) | 31 |
| | 7 |
| | 2 |
| | 1 |
| | 41 |
|
Total | $ | 3,544 |
| | $ | 4,996 |
| | $ | 4,287 |
| | $ | 10,075 |
| | $ | 22,902 |
|
| |
(a) | Amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2017, as reflected in the statements of capitalization. |
| |
(b) | Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers, and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. The Company provides guarantees to certain gas suppliers for certain of its subsidiaries, including SouthStar, in support of payment obligations. |
| |
(c) | Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. In terms of rental charges and duration of contracts, the Company's most significant operating leases relate to real estate. |
| |
(d) | Represent fixed-fee minimum payments for Sequent's affiliated asset management agreements. |
| |
(e) | See Notes 1 and 10 to the financial statements for additional information. |
| |
(f) | The Company forecasts contributions to the pension and other postretirement benefit plans over a three-year period. The Company anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from the Company's corporate assets. See Note 2 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from the Company's corporate assets. |
| |
(g) | Estimated capital expenditures are provided through 2022. Capital includes amounts related to Elizabethtown Gas and Elkton Gas, which represent $123 million in 2018, $249 million in 2019-2020, and $255 million in 2021-2022. See Note 11 to the financial statements under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information. Capital also includes amounts related to the Company's pipeline investments that will be recorded at the joint venture level, which represent $64 million in 2018, $195 million in 2019-2020, and less than $1 million in capital expenditures in 2021-2022. |
| |
(h) | Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms and long-term service agreements. |
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Cautionary Statement Regarding Forward-Looking Statements
The Company's 2017 Annual Report contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulatory matters, the strategic goals for the Company, economic conditions, natural gas price volatility, derivative losses, regulatory and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plan contributions, financing activities, completion dates of construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, and estimated other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:
the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which the Company is subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the recently enacted Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of the Company, Southern Company Gas Capital, and Nicor Gas;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which the Company operates;
variations in demand for natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas;
limits on pipeline capacity;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities;
investment performance of the Company's employee and retiree benefit plans;
advances in technology;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to natural gas and other cost recovery mechanisms;
the inherent risks involved in transporting and storing natural gas;
the ability to successfully operate the natural gas distribution and storage facilities and the successful performance of necessary corporate functions;
internal restructuring or other restructuring options that may be pursued;
potential business strategies, including acquisitions or dispositions of assets or businesses, including the proposed disposition of Elizabethtown Gas and Elkton Gas, which cannot be assured to be completed or beneficial to the Company;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to integration with Southern Company will be greater than expected;
the ability of counterparties of the Company to make payments as and when due and to perform as required;
the direct or indirect effect on the Company's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
changes in the Company's, Southern Company Gas Capital's, and Nicor Gas' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general;
MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Company's business resulting from incidents affecting the U.S. natural gas pipeline infrastructure or operation of storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports filed by the Company from time to time with the SEC.
The Company expressly disclaims any obligation to update any forward-looking statements.
CONSOLIDATED STATEMENTS OF INCOME
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the year ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | For the year ended December 31, |
| | 2017 | | 2016 | | | 2016 | | 2015 |
| | (in millions) | | | (in millions) |
Operating Revenues: | | | | | | | | | |
Natural gas revenues (includes revenue taxes of $100, $32, $57, and $103 for the periods presented, respectively) | | $ | 3,791 |
| | $ | 1,596 |
| | | $ | 1,841 |
| | $ | 3,817 |
|
Other revenues | | 129 |
| | 56 |
| | | 64 |
| | 124 |
|
Total operating revenues | | 3,920 |
| | 1,652 |
| | | 1,905 |
| | 3,941 |
|
Operating Expenses: | | | | | | | | | |
Cost of natural gas | | 1,601 |
| | 613 |
| | | 755 |
| | 1,617 |
|
Cost of other sales | | 29 |
| | 10 |
| | | 14 |
| | 28 |
|
Other operations and maintenance | | 940 |
| | 482 |
| | | 454 |
| | 928 |
|
Depreciation and amortization | | 501 |
| | 238 |
| | | 206 |
| | 397 |
|
Taxes other than income taxes | | 184 |
| | 71 |
| | | 99 |
| | 181 |
|
Merger-related expenses | | — |
| | 41 |
| | | 56 |
| | 44 |
|
Total operating expenses | | 3,255 |
| | 1,455 |
| | | 1,584 |
| | 3,195 |
|
Operating Income | | 665 |
| | 197 |
| | | 321 |
| | 746 |
|
Other Income and (Expense): | | | | | | | | | |
Earnings from equity method investments | | 106 |
| | 60 |
| | | 2 |
| | 6 |
|
Interest expense, net of amounts capitalized | | (200 | ) | | (81 | ) | | | (96 | ) | | (175 | ) |
Other income (expense), net | | 39 |
| | 14 |
| | | 5 |
| | 9 |
|
Total other income and (expense) | | (55 | ) | | (7 | ) | | | (89 | ) | | (160 | ) |
Earnings Before Income Taxes | | 610 |
| | 190 |
| | | 232 |
| | 586 |
|
Income taxes | | 367 |
| | 76 |
| | | 87 |
| | 213 |
|
Net Income | | 243 |
| | 114 |
| | | 145 |
| | 373 |
|
Less: Net income attributable to noncontrolling interest | | — |
| | — |
| | | 14 |
| | 20 |
|
Net Income Attributable to Southern Company Gas | | $ | 243 |
| | $ | 114 |
| | | $ | 131 |
| | $ | 353 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the year ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | For the year ended December 31, |
| | 2017 | | 2016 | | | 2016 | | 2015 |
| | (in millions) | | | (in millions) |
Net Income | | $ | 243 |
| | $ | 114 |
| | | $ | 145 |
| | $ | 373 |
|
Other comprehensive income (loss): | | | | | | | | | |
Qualifying hedges: | | | | | | | | | |
Changes in fair value, net of tax of $(3), $(1), $(23), and $(3), respectively | | (5 | ) | | (1 | ) | | | (41 | ) | | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $1, respectively | | 1 |
| | — |
| | | 1 |
| | 8 |
|
Pension and other postretirement benefit plans: | | | | | | | | | |
Benefit plan net gain (loss), net of tax of $-, $19, $-, and $-, respectively | | (1 | ) | | 27 |
| | | — |
| | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $4, and $9, respectively | | — |
| | — |
| | | 5 |
| | 12 |
|
Total other comprehensive income (loss) | | (5 | ) | | 26 |
| | | (35 | ) | | 20 |
|
Less: Comprehensive income attributable to noncontrolling interest | | — |
| | — |
| | | 14 |
| | 20 |
|
Comprehensive Income Attributable to Southern Company Gas | | $ | 238 |
| | $ | 140 |
| | | $ | 96 |
| | $ | 373 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | For the year ended December 31, | | July 1, 2016 through December 31, | | | January 1, 2016 through June 30, | | For the year ended December 31, |
| | 2017 | | 2016 | | | 2016 | | 2015 |
| | (in millions) | | | (in millions) |
Operating Activities: | | | | | | | | | |
Net income | | $ | 243 |
| | $ | 114 |
| | | $ | 145 |
| | $ | 373 |
|
Adjustments to reconcile net income to net cash provided from (used for) operating activities — | | | | | | | | | |
Depreciation and amortization, total | | 501 |
| | 238 |
| | | 206 |
| | 397 |
|
Deferred income taxes | | 236 |
| | 92 |
| | | 8 |
| | 211 |
|
Pension, postretirement, and other employee benefits | | (1 | ) | | 6 |
| | | 5 |
| | 24 |
|
Pension and postretirement funding | | — |
| | (125 | ) | | | — |
| | — |
|
Stock based compensation expense | | 32 |
| | 20 |
| | | 20 |
| | 34 |
|
Hedge settlements | | — |
| | (35 | ) | | | (26 | ) | | — |
|
Goodwill impairment | | — |
| | — |
| | | — |
| | 14 |
|
Mark-to-market adjustments | | (24 | ) | | (3 | ) | | | 162 |
| | 22 |
|
Other, net | | (83 | ) | | (78 | ) | | | (82 | ) | | 43 |
|
Changes in certain current assets and liabilities — | | | | | | | | | |
-Receivables | | (91 | ) | | (490 | ) | | | 181 |
| | 615 |
|
-Natural gas for sale, net of temporary LIFO liquidation | | 36 |
| | (226 | ) | | | 273 |
| | 72 |
|
-Prepaid income taxes | | (39 | ) | | (23 | ) | | | 151 |
| | 23 |
|
-Other current assets | | (24 | ) | | (31 | ) | | | 37 |
| | (11 | ) |
-Accounts payable | | (20 | ) | | 194 |
| | | 43 |
| | (434 | ) |
-Accrued taxes | | 110 |
| | 8 |
| | | 41 |
| | (20 | ) |
-Accrued compensation | | 15 |
| | (13 | ) | | | (21 | ) | | (6 | ) |
-Other current liabilities | | (8 | ) | | 24 |
| | | (30 | ) | | 24 |
|
Net cash provided from (used for) operating activities | | 883 |
| | (328 | ) | | | 1,113 |
| | 1,381 |
|
Investing Activities: | | | | | | | | | |
Property additions | | (1,514 | ) | | (614 | ) | | | (509 | ) | | (961 | ) |
Cost of removal, net of salvage | | (66 | ) | | (40 | ) | | | (32 | ) | | (84 | ) |
Change in construction payables, net | | 72 |
| | 22 |
| | | (7 | ) | | 18 |
|
Investment in unconsolidated subsidiaries | | (145 | ) | | (1,444 | ) | | | (14 | ) | | (12 | ) |
Returned investment in unconsolidated subsidiaries | | 80 |
| | 5 |
| | | 3 |
| | 12 |
|
Other investing activities | | 3 |
| | 4 |
| | | — |
| | — |
|
Net cash used for investing activities | | (1,570 | ) | | (2,067 | ) | | | (559 | ) | | (1,027 | ) |
Financing Activities: | | | | | | | | | |
Increase (decrease) in notes payable, net | | 262 |
| | 1,143 |
| | | (896 | ) | | (165 | ) |
Proceeds — | | | | | | | | | |
First mortgage bonds | | 400 |
| | — |
| | | 250 |
| | — |
|
Capital contributions from parent company | | 103 |
| | 1,085 |
| | | — |
| | — |
|
Senior notes | | 450 |
| | 900 |
| | | 350 |
| | 250 |
|
Redemptions and repurchases — | | | | | | | | | |
Medium-term notes | | (22 | ) | | — |
| | | — |
| | — |
|
First mortgage bonds | | — |
| | — |
| | | (125 | ) | | — |
|
Senior notes | | — |
| | (420 | ) | | | — |
| | (200 | ) |
Distribution to noncontrolling interest | | — |
| | (15 | ) | | | (19 | ) | | (18 | ) |
Purchase of 15% noncontrolling interest in SouthStar | | — |
| | (160 | ) | | | — |
| | — |
|
Payment of common stock dividends | | (443 | ) | | (126 | ) | | | (128 | ) | | (244 | ) |
Other financing activities | | (9 | ) | | (8 | ) | | | 10 |
| | 11 |
|
Net cash provided from (used for) financing activities | | 741 |
| | 2,399 |
| | | (558 | ) | | (366 | ) |
Net Change in Cash and Cash Equivalents | | 54 |
| | 4 |
| | | (4 | ) | | (12 | ) |
Cash and Cash Equivalents at Beginning of Period | | 19 |
| | 15 |
| | | 19 |
| | 31 |
|
Cash and Cash Equivalents at End of Period | | $ | 73 |
| | $ | 19 |
| | | $ | 15 |
| | $ | 19 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | |
Assets | | 2017 | | 2016 |
| | (in millions) |
Current Assets: | | | | |
Cash and cash equivalents | | $ | 73 |
| | $ | 19 |
|
Receivables — | | | | |
Energy marketing receivable | | 607 |
| | 623 |
|
Customer accounts receivable | | 400 |
| | 364 |
|
Unbilled revenues | | 285 |
| | 239 |
|
Other accounts and notes receivable | | 103 |
| | 76 |
|
Accumulated provision for uncollectible accounts | | (28 | ) | | (27 | ) |
Materials and supplies | | 24 |
| | 26 |
|
Natural gas for sale | | 595 |
| | 631 |
|
Prepaid income taxes | | 26 |
| | 24 |
|
Prepaid expenses | | 53 |
| | 55 |
|
Assets from risk management activities, net of collateral | | 135 |
| | 128 |
|
Other regulatory assets, current | | 94 |
| | 81 |
|
Other current assets | | 28 |
| | 11 |
|
Total current assets | | 2,395 |
| | 2,250 |
|
Property, Plant, and Equipment: | | | | |
In service | | 15,833 |
| | 14,508 |
|
Less: Accumulated depreciation | | 4,596 |
| | 4,439 |
|
Plant in service, net of depreciation | | 11,237 |
| | 10,069 |
|
Construction work in progress | | 491 |
| | 496 |
|
Total property, plant, and equipment | | 11,728 |
| | 10,565 |
|
Other Property and Investments: | | | | |
Goodwill | | 5,967 |
| | 5,967 |
|
Equity investments in unconsolidated subsidiaries | | 1,477 |
| | 1,541 |
|
Other intangible assets, net of amortization of $120 and $34 at December 31, 2017 and December 31, 2016, respectively | | 280 |
| | 366 |
|
Miscellaneous property and investments | | 21 |
| | 21 |
|
Total other property and investments | | 7,745 |
| | 7,895 |
|
Deferred Charges and Other Assets: | | | | |
Other regulatory assets, deferred | | 901 |
| | 973 |
|
Other deferred charges and assets | | 218 |
| | 170 |
|
Total deferred charges and other assets | | 1,119 |
| | 1,143 |
|
Total Assets | | $ | 22,987 |
| | $ | 21,853 |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
At December 31, 2017 and 2016
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | |
Liabilities and Stockholder's Equity | | 2017 | | 2016 |
| | (in millions) |
Current Liabilities: | | | | |
Securities due within one year | | $ | 157 |
| | $ | 22 |
|
Notes payable | | 1,518 |
| | 1,257 |
|
Energy marketing trade payables | | 546 |
| | 597 |
|
Accounts payable | | 446 |
| | 348 |
|
Customer deposits | | 128 |
| | 153 |
|
Accrued taxes — | | | | |
Accrued income taxes | | 40 |
| | 26 |
|
Other accrued taxes | | 78 |
| | 68 |
|
Accrued interest | | 51 |
| | 48 |
|
Accrued compensation | | 74 |
| | 58 |
|
Liabilities from risk management activities, net of collateral | | 69 |
| | 62 |
|
Other regulatory liabilities, current | | 135 |
| | 102 |
|
Accrued environmental remediation, current | | 46 |
| | 69 |
|
Other current liabilities | | 113 |
| | 108 |
|
Total current liabilities | | 3,401 |
| | 2,918 |
|
Long-term Debt (See accompanying statements) | | 5,891 |
| | 5,259 |
|
Deferred Credits and Other Liabilities: | | | | |
Accumulated deferred income taxes | | 1,089 |
| | 1,975 |
|
Deferred credits related to income taxes | | 1,063 |
| | 22 |
|
Employee benefit obligations | | 415 |
| | 441 |
|
Other cost of removal obligations | | 1,646 |
| | 1,616 |
|
Accrued environmental remediation, deferred | | 342 |
| | 357 |
|
Other regulatory liabilities, deferred | | 30 |
| | 29 |
|
Other deferred credits and liabilities | | 88 |
| | 127 |
|
Total deferred credits and other liabilities | | 4,673 |
| | 4,567 |
|
Total Liabilities | | 13,965 |
| | 12,744 |
|
Common Stockholder's Equity (See accompanying statements) | | 9,022 |
| | 9,109 |
|
Total Liabilities and Stockholder's Equity | | $ | 22,987 |
| | $ | 21,853 |
|
Commitments and Contingent Matters (See notes) | |
| |
|
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 2017 and 2016
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | |
| 2017 |
| | 2016 |
| | 2017 |
| | 2016 |
|
| (in millions) | | (percent of total) |
Long-Term Debt: | | | | | | | |
Long-term notes payable — | | | | | | | |
7.20% due 2017 | $ | — |
| | $ | 22 |
| | | | |
3.50% due 2018 | 155 |
| | 155 |
| | | | |
5.25% due 2019 | 300 |
| | 300 |
| | | | |
3.50% to 9.10% due 2021 | 330 |
| | 330 |
| | | | |
8.55% to 8.70% due 2022 | 46 |
| | 46 |
| | | | |
2.45% to 7.30% due 2023-2047 | 3,484 |
| | 3,034 |
| | | | |
Total long-term notes payable | 4,315 |
| | 3,887 |
| | | | |
Other long-term debt — | | | | | | | |
First mortgage bonds — | | | | | | | |
4.70% due 2019 | 50 |
| | 50 |
| | | | |
2.66% to 6.58% due 2023-2057 | 975 |
| | 575 |
| | | | |
Gas facility revenue bonds — | | | | | | | |
Variable rate (1.71% at 12/31/17) due 2022 | 47 |
| | 47 |
| | | | |
Variable rate (1.71% at 12/31/17) due 2024-2033 | 153 |
| | 153 |
| | | | |
Total other long-term debt | 1,225 |
| | 825 |
| | | | |
Unamortized fair value adjustment of long-term debt | 525 |
| | 578 |
| | | | |
Unamortized debt discount | (17 | ) | | (9 | ) | | | | |
Total long-term debt (annual interest requirement — $241 million) | 6,048 |
| | 5,281 |
| | | | |
Less amount due within one year | 157 |
| | 22 |
| | | | |
Long-term debt excluding amount due within one year | 5,891 |
| | 5,259 |
| | 39.5 | % | | 36.6 | % |
Common Stockholder's Equity: | | | | | | | |
Common stock — par value $0.01 per share | | | | | | | |
Authorized — 100 million shares | | | | | | | |
Outstanding — 100 shares | | | | | | | |
Paid-in capital | 9,214 |
| | 9,095 |
| | | | |
Accumulated deficit | (212 | ) | | (12 | ) | | | | |
Accumulated other comprehensive income | 20 |
| | 26 |
| | | | |
Total common stockholder's equity | 9,022 |
| | 9,109 |
| | 60.5 |
| | 63.4 |
|
Total Capitalization | $ | 14,913 |
| | $ | 14,368 |
| | 100.0 | % | | 100.0 | % |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern Company Gas Common Stockholders' Equity | | | |
| Number of Common Shares | | Common Stock | | | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | |
| Issued | | Treasury | | Par Value | | Paid-In Capital | | Treasury | | Retained Earnings (Accumulated Deficit) | | | Total |
| (in thousands) | | (in millions) |
Predecessor – Balance at December 31, 2014 | 119,647 |
| | 217 |
| | $ | 599 |
| | $ | 2,087 |
| | $ | (8 | ) | | $ | 1,312 |
| | $ | (206 | ) | | $ | 44 |
| $ | 3,828 |
|
Consolidated net income attributable to Southern Company Gas | — |
| | — |
| | — |
| | — |
| | — |
| | 353 |
| | — |
| | — |
| 353 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| 20 |
|
Stock issued | 221 |
| | — |
| | 1 |
| | 11 |
| | — |
| | — |
| | — |
| | — |
| 12 |
|
Stock-based compensation | 509 |
| | — |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| 4 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | — |
| | — |
| | (244 | ) | | — |
| | — |
| (244 | ) |
Distribution to noncontrolling interest(*) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | (18 | ) |
Net income attributable to noncontrolling interest (*) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| 20 |
|
Predecessor – Balance at December 31, 2015 | 120,377 |
| | 217 |
| | 603 |
| | 2,099 |
| | (8 | ) | | 1,421 |
| | (186 | ) | | 46 |
| 3,975 |
|
Consolidated net income attributable to Southern Company Gas | — |
| | — |
| | — |
| | — |
| | — |
| | 131 |
| | — |
| | — |
| 131 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (35 | ) | | — |
| (35 | ) |
Stock issued | 95 |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| 6 |
|
Stock-based compensation | 270 |
| | — |
| | 2 |
| | 28 |
| | — |
| | — |
| | — |
| | — |
| 30 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | — |
| | — |
| | (128 | ) | | — |
| | — |
| (128 | ) |
Reclassification of noncontrolling interest (*) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (46 | ) | (46 | ) |
Predecessor – Balance at June 30, 2016 | 120,742 |
| | 217 |
| | 605 |
| | 2,133 |
| | (8 | ) | | 1,424 |
| | (221 | ) | | — |
| 3,933 |
|
Successor – Balance at July 1, 2016 | — |
| | — |
| | — |
| | 8,001 |
| | — |
| | — |
| | — |
| | — |
| 8,001 |
|
Consolidated net income attributable to Southern Company Gas | — |
| | — |
| | — |
| | — |
| | — |
| | 114 |
| | — |
| | — |
| 114 |
|
Capital contributions from parent company | — |
| | — |
| | — |
| | 1,094 |
| | — |
| | — |
| | — |
| | — |
| 1,094 |
|
Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 26 |
| | — |
| 26 |
|
Cash dividends on common stock | — |
| | — |
| | — |
| | — |
| | — |
| | (126 | ) | | — |
| | — |
| (126 | ) |
Successor – Balance at December 31, 2016 | — |
| | — |
| | — |
| | 9,095 |
| | — |
| | (12 | ) | | 26 |
| | — |
| 9,109 |
|
Consolidated net income attributable to Southern Company Gas | — |
| | — |
| | — |
| | — |
| | — |
| | 243 |
| | — |
| | — |
| 243 |
|
Capital contributions from parent company, net | — |
| | — |
| | — |
| | 117 |
| | — |
| | — |
| | — |
| | — |
| 117 |
|
Other comprehensive income (loss) | — |
| | — |
| | | | — |
| | — |
| | — |
| | (5 | ) | | — |
| (5 | ) |
Cash dividends on common stock | — |
| | — |
| | — |
| | — |
| | — |
| | (443 | ) | | — |
| | — |
| (443 | ) |
Other | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | (1 | ) | | — |
| 1 |
|
Successor – Balance at December 31, 2017 | — |
| | — |
| | $ | — |
| | $ | 9,214 |
| | $ | — |
| | $ | (212 | ) | | $ | 20 |
| | $ | — |
| $ | 9,022 |
|
|
| |
(*) | Associated with SouthStar. See Note 4 to the financial statements for additional information. |
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO FINANCIAL STATEMENTS
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Index to the Notes to Financial Statements
|
| | |
Note | | Page |
1 | | |
2 | | |
3 | | |
4 | | |
5 | | |
6 | | |
7 | | |
8 | | |
9 | | |
10 | | |
11 | | |
12 | | |
13 | | |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
On July 1, 2016, Southern Company and Southern Company Gas (together with its subsidiaries, the Company) completed the Merger and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company. In addition to the Company, Southern Company is the parent company of four traditional electric operating companies, Southern Power, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, Inc., and other direct and indirect subsidiaries. The Company is an energy services holding company whose primary business is the distribution of natural gas across seven states through its seven natural gas distribution utilities. The Company also is involved in several other businesses that are complementary to the distribution of natural gas. The traditional electric operating companies – Alabama Power Company, Georgia Power Company, Gulf Power Company, and Mississippi Power Company – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and for other electric services. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. PowerSecure, Inc. is a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure.
The financial statements reflect the Company's investments in its subsidiaries on a consolidated basis. The equity method is used for subsidiaries in which the Company has significant influence but does not control and for VIEs where the Company has an equity investment, but is not the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
The seven natural gas distribution utilities are subject to regulation by the regulatory agencies of each state in which they operate. As such, the Company's financial statements reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.
Pursuant to the Merger, Southern Company has pushed down the application of the acquisition method of accounting to the financial statements of the Company such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the financial statements of the Company for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout the financial statements and notes to the financial statements, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."
Certain predecessor period data presented in the financial statements has been modified or reclassified to conform to the presentation used by the Company's new parent company, Southern Company. Changes to the statements of income include classifying operating revenues as natural gas revenues and other revenues as well as classifying cost of goods sold as cost of natural gas and cost of other sales, and presenting interest expense and AFUDC on a gross basis. Changes to the statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each category of cash flow activity. Changes to the balance sheets include changing certain captions to conform to the presentation of Southern Company.
Recently Issued Accounting Standards
Revenue
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
Most of the Company's revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company's financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.
The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, quarterly disclosures will include comparative information on 2018 financial statement line items under current guidance. The adoption of ASC 606 did not result in a cumulative-effect adjustment.
Leases
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.
The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to real estate and fleet vehicles where the Company is the lessee and to natural gas home appliances where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to have a significant impact on the Company's balance sheet.
Other
In March 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions effective for fiscal years beginning after December 15, 2016. The new guidance requires all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation to be recognized as income tax expense or benefit in the income statement. Previously, the Company recognized any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. In addition, the new guidance requires excess tax benefits for share-based payments to be included in net cash provided from operating activities rather than net cash provided from financing activities on the statement of cash flows. The Company elected to adopt the guidance in 2016 and reflect the related adjustments as of January 1, 2016. Prior year's data presented in the financial statements has not been adjusted. The Company also elected to recognize forfeitures as they occur. The new guidance did not have a material impact on the results of operations, financial position, or cash flows of the Company. See Note 5 for the disclosure impacted by ASU 2016-09.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statement of cash flows. Upon adoption, the net change in cash and cash equivalents during the period will include amounts generally described as restricted cash or restricted cash equivalents. ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and will be applied retrospectively to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 with no material impact on its financial statements.
On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. The Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in the Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.
On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.
Affiliate Transactions
SCS, as agent for Alabama Power, Georgia Power, and Southern Power, and the Company have long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and the Company by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the successor year ended December 31, 2017, transportation revenue under these agreements from SCS and the Company were $136 million and $32 million, respectively. For the successor period of September 1, 2016 through December 31, 2016, transportation revenue under these agreements from SCS and the Company were $32 million and $15 million, respectively. See Note 4 under "Equity Method Investments – SNG" for additional information regarding the Company's investment in SNG.
The Company has an agreement with SCS under which the following services are currently being rendered to the Company as direct or allocated cost: accounting, finance and treasury, tax, information technology, auditing, insurance and pension administration, human resources, systems and procedures, purchasing, and other services. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, costs for these services amounted to $63 million and $17 million, respectively. Cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
SCS, as agent for Alabama Power, Georgia Power, and Southern Power, has agreements with certain subsidiaries of the Company to purchase natural gas. For the successor year ended December 31, 2017, natural gas purchases made by SCS from the Company's subsidiaries were $142 million. For the successor period of July 1, 2016 through December 31, 2016, natural gas purchases made by SCS from the Company's subsidiaries were $27 million.
Regulatory Assets and Liabilities
The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
|
| | | | | | | | | |
| 2017 | | 2016 | | Note |
| (in millions) | | |
Environmental remediation | $ | 410 |
| | $ | 411 |
| | (a,b) |
Retiree benefit plans | 270 |
| | 325 |
| | (a,c) |
Long-term debt fair value adjustment | 138 |
| | 154 |
| | (d) |
Under recovered regulatory clause revenues | 98 |
| | 118 |
| | (e) |
Other regulatory assets | 79 |
| | 58 |
| | (f) |
Other cost of removal obligations | (1,646 | ) | | (1,616 | ) | | (g) |
Deferred income tax credits | (1,063 | ) | | (22 | ) | | (g,i) |
Over recovered regulatory clause revenues | (144 | ) | | (104 | ) | | (e) |
Other regulatory liabilities | (21 | ) | | (39 | ) | | (h) |
Total regulatory assets (liabilities), net | $ | (1,879 | ) | | $ | (715 | ) | | |
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows:
| |
(a) | Not earning a return as offset in rate base by a corresponding asset or liability. |
| |
(b) | Recovered through environmental cost recovery mechanisms when the remediation is performed or the work is performed. |
| |
(c) | Recovered and amortized over the average remaining service period which range up to 15 years. See Note 2 for additional information. |
| |
(d) | Recovered over the remaining life of the original debt issuances, which range up to 21 years. |
| |
(e) | Recorded and recovered or amortized as approved or accepted by the appropriate state regulatory agencies over periods generally not exceeding eight years. |
| |
(f) | Comprised of several components including unamortized loss on reacquired debt, weather normalization, franchise gas, deferred depreciation expense, and financial instrument-hedging assets, which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding 10 years, except for financial hedging-instruments. Financial instrument-hedging assets are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. |
| |
(g) | Other cost of removal obligations are recorded and deferred income tax liabilities are amortized over the related property lives, which may range up to 80 years. Cost of removal liabilities will be settled and trued up following completion of the related activities. |
| |
(h) | Comprised of several components including energy efficiency programs, unamortized bond issuance costs and financial instrument-hedging liabilities which are recovered or amortized as approved by the applicable state regulatory agencies over periods generally not exceeding a range of four years to 20 years, except for financial hedging-instruments. Financial instrument-hedging liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered, and actual income earned is refunded through the energy cost recovery clause. |
| |
(i) | Includes excess deferred income tax liabilities not subject to normalization as a result of the Tax Reform Legislation, the recovery and amortization of which will be determined by the applicable state regulatory agencies. See Note 3 under "Regulatory Matters" and Note 5 for additional details. |
In the event that a portion of a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Regulatory Matters" for additional information.
Revenues
Gas Distribution Operations
The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the Company's utilities. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class.
All of the natural gas distribution utilities, with the exception of Atlanta Gas Light, have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries to the end of the period.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The tariffs for several of the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, so long as the amounts recognized will be collected from customers within 24 months of recognition. These programs are as follows:
Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas, Elizabethtown Gas, and Chattanooga Gas;
Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas, Chattanooga Gas, and Elkton Gas; and
Revenue true-up adjustment – included within the provisions of the Georgia Rate Adjustment Mechanism (GRAM) program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a monthly positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year.
Revenue Taxes
The Company charges customers for gas revenue and gas use taxes imposed on the Company and remits amounts owed to various governmental authorities. Gas revenue taxes are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on the Company are recorded as operating expenses on the statements of income. Gas use taxes are excluded from revenue and expense with the related administrative fee included in operating revenues when the tax is imposed on the customer. Revenue taxes included in operating expenses were $98 million and $31 million for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, respectively, and $56 million and $101 million for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, respectively.
Gas Marketing Services
The Company recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. The Company also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.
The Company recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts. Revenues for warranty and repair contracts are recognized on a straight-line basis over the contract term while revenues for maintenance services are recognized at the time such services are performed.
Wholesale Gas Services
The Company nets revenues from energy and risk management activities with the associated costs. Profits from sales between segments are eliminated and are recognized as goods or services sold to end-use customers. The Company records transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.
Concentration of Revenue
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues.
Cost of Natural Gas and Other Sales
Gas Distribution Operations
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the Company charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
Gas Marketing Services
The Company's gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, the Company also includes costs of fuel and lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, and gains and losses associated with certain derivatives. The Company records the costs to service its warranty and repair contract claims as cost of other sales.
Income and Other Taxes
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheet, excluding revenue taxes which are presented on the statements of income. See "Revenues – Gas Distribution Operations – Revenue Taxes" herein for additional information.
The Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost, or fair value at the effective date of the Merger as appropriate, less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.
The Company's property, plant, and equipment in service consisted of the following at December 31:
|
| | | | | | | | |
| 2017 | | | 2016 |
| (in millions) |
Utility plant in service | $ | 13,079 |
| | | $ | 11,996 |
|
Information technology equipment and software | 366 |
| | | 324 |
|
Storage facilities | 1,599 |
| | | 1,463 |
|
Other | 789 |
| | | 725 |
|
Total other plant in service | 2,754 |
| | | 2,512 |
|
Total plant in service | $ | 15,833 |
| | | $ | 14,508 |
|
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. The portion of non-working gas used to maintain the structural integrity of the Company's natural gas storage facilities that is considered to be non-recoverable is recorded as depreciable property, plant, and equipment, while the recoverable or retained portion is recorded as non-depreciable property, plant, and equipment.
The amount of non-cash property additions recognized for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $135 million, $63 million, $41 million, and $48 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at the end of each period.
Depreciation and Amortization
Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.9% in 2017, 2.8% in 2016, and 2.7% in 2015. Depreciation studies are conducted periodically to update the composite rates that are approved by the respective state regulatory agency. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over the following useful lives: five to 15 years for transportation equipment, 40 to 60 years for storage facilities, and up to 65 years for other assets.
Allowance for Funds Used During Construction
The Company records AFUDC for Atlanta Gas Light, Nicor Gas, Chattanooga Gas, and Elizabethtown Gas, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The capital expenditures of the other three natural gas utilities do not qualify for AFUDC treatment.
The Company's AFUDC composite rates are as follows:
|
| | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
Atlanta Gas Light | 8.10 | % | | | 4.05 | % | | | 4.05 | % | | 8.10 | % |
Chattanooga Gas | 7.41 |
| | | 3.71 |
| | | 3.71 |
| | 7.41 |
|
Elizabethtown Gas(*) | 1.56 |
| | | 0.84 |
| | | 0.84 |
| | 1.69 |
|
Nicor Gas(*) | 1.22 |
| | | 1.50 |
| | | 1.50 |
| | 0.82 |
|
| |
(*) | Variable rate is determined by the FERC method of AFUDC accounting. |
Cash payments for interest during the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 totaled $223 million, $135 million, $119 million, and $181 million, respectively.
Impairment of Long-Lived Assets
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Other Matters" for additional information.
Goodwill and Other Intangible Assets and Liabilities
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any.
For the 2017 annual impairment test, the Company performed Step 1 of the two-step impairment test, which resulted in the fair value of all its reporting units that have goodwill exceeding their carrying value. For the 2016 and 2015 annual impairment tests, the Company performed the qualitative Step 0 assessment and determined that it was more likely than not that the fair value of all its reporting units with goodwill exceeded their carrying values, and therefore no quantitative assessment was required. In the third quarter 2015, the Company identified potential impairment indicators and performed an interim impairment test for its storage and fuels reporting unit, which resulted in impairment of the full $14 million goodwill balance for that reporting unit.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Goodwill and other intangible assets consisted of the following:
|
| | | | | | | | | | | | | |
| | | At December 31, 2017 |
| Estimated Useful Life | | Gross Carrying Amount | | Accumulated Amortization | | Other Intangible Assets, Net |
| | | (in millions) |
Other intangible assets subject to amortization: | | | | | | | |
Gas marketing services | | | | | | | |
Customer relationships | 11-16 years | | $ | 221 |
| | $ | (77 | ) | | $ | 144 |
|
Trade names | 10-28 years | | 115 |
| | (9 | ) | | 106 |
|
Wholesale gas services | | | | | | | |
Storage and transportation contracts | 1-5 years | | 64 |
| | (34 | ) | | 30 |
|
Total intangible assets subject to amortization | | | $ | 400 |
| | $ | (120 | ) | | $ | 280 |
|
| | | | | | | |
Goodwill: | | | | | | | |
Gas distribution operations | | | $ | 4,702 |
| | $ | — |
| | $ | 4,702 |
|
Gas marketing services | | | 1,265 |
| | — |
| | 1,265 |
|
Total goodwill | | | $ | 5,967 |
| | $ | — |
| | $ | 5,967 |
|
|
| | | | | | | | | | | | | |
| | | At December 31, 2016 |
| Estimated Useful Life | | Gross Carrying Amount | | Accumulated Amortization | | Other Intangible Assets, Net |
| | | (in millions) |
Other intangible assets subject to amortization: | | | | | | | |
Gas marketing services | | | | | | | |
Customer relationships | 11-16 years | | $ | 221 |
| | $ | (30 | ) | | $ | 191 |
|
Trade names | 10-28 years | | 115 |
| | (2 | ) | | 113 |
|
Wholesale gas services | | | | | | | |
Storage and transportation contracts | 1-5 years | | 64 |
| | (2 | ) | | 62 |
|
Total intangible assets subject to amortization | | | $ | 400 |
| | $ | (34 | ) | | $ | 366 |
|
| | | | | | | |
Goodwill: | | | | | | | |
Gas distribution operations | | | $ | 4,702 |
| | $ | — |
| | $ | 4,702 |
|
Gas marketing services | | | 1,265 |
| | — |
| | 1,265 |
|
Total goodwill | | | $ | 5,967 |
| | $ | — |
| | $ | 5,967 |
|
Amortization associated with intangible assets for gas marketing services, included in depreciation and amortization, for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 was $54 million, $32 million, $8 million, and $18 million, respectively. Amortization of $32 million and $2 million for wholesale gas services was recorded as a reduction to operating revenues for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, respectively.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, the estimated amortization associated with other intangible assets is as follows: |
| | | |
| Amortization |
| (in millions) |
2018 | $ | 58 |
|
2019 | 40 |
|
2020 | 28 |
|
2021 | 21 |
|
2022 | 17 |
|
Included in other deferred credits and liabilities on the balance sheets is $91 million of intangible liabilities that were recorded during acquisition accounting for transportation contracts at wholesale gas services. At December 31, 2017, the accumulated amortization of these intangible liabilities was $50 million. The estimated amortization associated with the intangible liabilities that will be recorded in natural gas revenues is as follows:
|
| | | |
| Amortization |
| (in millions) |
2018 | $ | 24 |
|
2019 | 17 |
|
Cash and Cash Equivalents
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
Energy Marketing Receivables and Payables
Wholesale gas services provides services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilize netting agreements that enable wholesale gas services to net receivables and payables by counterparty upon settlement. Wholesale gas services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale gas services' counterparties are settled net, they are recorded on a gross basis in the balance sheets as energy marketing receivables and energy marketing payables.
Wholesale gas services has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if the Company's credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale gas services would need to post collateral to continue transacting business with some of its counterparties. As of December 31, 2017 and 2016, the required collateral in the event of a credit rating downgrade was $8 million and immaterial, respectively.
Wholesale gas services has a concentration of credit risk for services it provides to its counterparties. This credit risk is generally concentrated in 20 of its counterparties and is measured by 30-day receivable exposure plus forward exposure. Counterparty credit risk is evaluated using an S&P equivalent credit rating, which is determined by a process of converting the lower of the S&P or Moody's rating to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being equivalent to D/Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of its financial ratios. As of December 31, 2017, the top 20 counterparties represented 48%, or $203 million, of the total counterparty exposure and had a weighted average S&P equivalent rating of A-.
Credit policies were established to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. When wholesale gas services is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty combined with a reasonable measure of the Company's credit risk. Wholesale gas services also uses other netting agreements with certain counterparties with whom it conducts significant transactions.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Receivables and Provision for Uncollectible Accounts
The Company's other trade receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible.
Nicor Gas
Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year.
Atlanta Gas Light
Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 Marketers in Georgia. The credit risk exposure to Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light.
Materials and Supplies
Generally, materials and supplies include propane gas inventory, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.
Natural Gas for Sale
The natural gas distribution utilities, with the exception of Nicor Gas, record natural gas inventories on a WACOG basis. In Georgia's competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.
Nicor Gas' inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on the Company's net income. At December 31, 2017, the Nicor Gas LIFO inventory balance was $148 million. Based on the average cost of gas purchased in December 2017, the estimated replacement cost of Nicor Gas' inventory at December 31, 2017 was $264 million. During 2017, Nicor Gas did not liquidate any LIFO-based inventory.
The gas marketing services, wholesale gas services, and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, the Company evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, the Company recorded the following LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2017 | | July 1, 2016 to December 31, 2016 | | | January 1, 2016 to June 30, 2016 | | 2015 |
| (in millions) | | | (in millions) |
Gas marketing services | $ | — |
| | $ | — |
| | | $ | — |
| | $ | 3 |
|
Wholesale gas services | 2 |
| | 1 |
| | | 3 |
| | 19 |
|
All other | — |
| | — |
| | | — |
| | 1 |
|
Total LOCOM adjustments | $ | 2 |
| | $ | 1 |
| | | $ | 3 |
| | $ | 23 |
|
Fair Value Measurements
The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents and derivative instruments. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate their respective fair value. The nonfinancial assets and liabilities include pension and other postretirement benefits. See Notes 2 and 9 for additional fair value disclosures.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:
Level 1
Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company's Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets.
Level 2
Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include shorter tenor exchange-traded and non-exchange-traded derivatives such as over-the-counter (OTC) forwards and options and certain retirement plan assets.
Level 3
Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management's best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company's pension and other postretirement benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.
Financial Instruments
The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 10 for additional information regarding derivatives.
The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017.
The Company enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income.
Wholesale gas services purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price that can be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. The Company enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value recorded in natural gas revenues on the statements of income in the period of change. These contracts are not designated as hedges for accounting purposes.
The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.
The Company is exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.
Non-Wholly Owned Entities
The Company holds ownership interests in a number of business ventures with varying ownership structures and evaluates all of its partnership interests and other variable interests to determine if each entity is a VIE. If a venture is a VIE for which the Company is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Company reassesses its conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events under the guidance. See Note 4 under "Variable Interest Entities" for additional information.
For entities that are not determined to be VIEs, the Company evaluates whether it has control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of the Company are consolidated, and entities over which the Company can exert significant influence, but does not control, are accounted for under the equity method of accounting. However, the Company also invests in partnerships and limited liability companies that maintain separate ownership accounts. All such investments are required to be accounted for under the equity method unless the interest is so minor that there is virtually no influence over operating and financial policies, as are all investments in joint ventures.
Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries within the other property and investments section in the balance sheets and the equity income is recorded within earnings from equity
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
method investments within the other income (expense) section in the statements of income. See Note 4 under "Equity Method Investments" for additional information.
2. RETIREMENT BENEFITS
The Company has a qualified defined benefit, trusteed, pension plan covering most eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2017 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2018. The Company also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. The Company also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2018, no other postretirement trust contributions are expected.
In connection with the Merger, the Company performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. This valuation resulted in increases to the projected benefit obligations for the pension and other postretirement benefit plans of approximately $177 million and $20 million, respectively, a decrease in the fair value of pension plan assets of $10 million, and an increase in the fair value of other postretirement benefit plan assets of $1 million. The Company also recorded a related regulatory asset of $437 million related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates for the natural gas distribution utilities. The previously unrecognized prior service cost and actuarial gain/loss related to non-utility subsidiaries were eliminated through purchase accounting adjustments.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for all periods presented and the benefit obligations as of the measurement date are presented below.
|
| | | | | | | | | | |
| Successor | | | Predecessor |
Assumptions used to determine net periodic costs: | Year ended December 31, 2017 | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | Year ended December 31, 2015 |
Pension plans | | | | | | |
Discount rate – interest costs(a) | 3.76 | % | 3.21 | % | | | 4.00 | % | 4.20 | % |
Discount rate – service costs(a) | 4.64 |
| 4.07 |
| | | 4.80 |
| 4.20 |
|
Expected long-term return on plan assets | 7.60 |
| 7.75 |
| | | 7.80 |
| 7.80 |
|
Annual salary increase | 3.50 |
| 3.50 |
| | | 3.70 |
| 3.70 |
|
Pension band increase(b) | N/A |
| 2.00 |
| | | 2.00 |
| 2.00 |
|
Other postretirement benefit plans | |
| |
| | | | |
Discount rate – interest costs(a) | 3.40 | % | 2.84 | % | | | 3.60 | % | 4.00 | % |
Discount rate – service costs(a) | 4.55 |
| 3.96 |
| | | 4.70 |
| 4.00 |
|
Expected long-term return on plan assets | 6.03 |
| 5.93 |
| | | 6.60 |
| 7.80 |
|
Annual salary increase | 3.50 |
| 3.50 |
| | | 3.70 |
| 3.70 |
|
| |
(a) | Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate. |
| |
(b) | Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | |
Assumptions used to determine benefit obligations: | 2017 | | 2016 |
Pension plans | | | |
Discount rate | 3.74 | % | | 4.39 | % |
Annual salary increase | 2.88 |
| | 3.50 |
|
Pension band increase(*) | N/A |
| | 2.00 |
|
Other postretirement benefit plans | |
| | |
Discount rate | 3.62 | % | | 4.15 | % |
Annual salary increase | 2.56 |
| | 3.50 |
|
| |
(*) | Only applicable to Nicor Gas union employees. The pension bands for the former Nicor plan reflect the negotiated rates in accordance with the union agreements. |
The Company estimates the expected return on pension plan and other postretirement benefit plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year's annual pension or other postretirement benefit plan cost; rather, this gain or loss reduces or increases future pension or other postretirement benefit plan costs.
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
|
| | | | | | | |
| Initial Cost Trend Rate | | Ultimate Cost Trend Rate | | Year That Ultimate Rate is Reached |
Pre-65 | 6.40 | % | | 4.50 | % | | 2038 |
Post-65 medical | 7.80 |
| | 4.50 |
| | 2038 |
Post-65 prescription | 7.80 |
| | 4.50 |
| | 2038 |
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2017 as follows:
|
| | | | | | | |
| 1 Percent Increase | | 1 Percent Decrease |
| (in millions) |
Benefit obligation | $ | 11 |
| | $ | (10 | ) |
Service and interest costs | — |
| | — |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Pension Plans
The total accumulated benefit obligation for the pension plans was $1.1 billion at December 31, 2017 and $1.1 billion at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets for all periods presented were as follows: |
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 |
| (in millions) | | | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of period | $ | 1,133 |
| | $ | 1,244 |
| ` | | $ | 1,067 |
|
Service cost | 23 |
| | 15 |
| | | 13 |
|
Interest cost | 42 |
| | 20 |
| | | 21 |
|
Plan amendments | (26 | ) | | — |
| | | — |
|
Benefits paid | (91 | ) | | (31 | ) | | | (26 | ) |
Actuarial (gain) loss | 103 |
| | (115 | ) | | | 169 |
|
Balance at end of period | 1,184 |
| | 1,133 |
| | | 1,244 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of period | 983 |
| | 837 |
| ` | | 847 |
|
Actual return (loss) on plan assets | 175 |
| | 48 |
| | | 15 |
|
Employer contributions | 1 |
| | 129 |
| | | 1 |
|
Benefits paid | (91 | ) | | (31 | ) | | | (26 | ) |
Fair value of plan assets at end of period | 1,068 |
| | 983 |
| | | 837 |
|
Accrued liability | $ | 116 |
| | $ | 150 |
| | | $ | 407 |
|
At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $1.1 billion and $44 million, respectively. All pension plan assets are related to the qualified pension plan.
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's pension plans consist of the following:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Other regulatory assets, deferred | $ | 217 |
| | $ | 267 |
|
Other deferred charges and assets | 85 |
| | 58 |
|
Other current liabilities | (3 | ) | | (2 | ) |
Employee benefit obligations | (198 | ) | | (206 | ) |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
|
| | | | | | | | | | | |
| Regulatory Amortization | | Prior Service Cost | | Net (Gain) Loss |
| (in millions)
|
Balance at December 31, 2017: | | | | | |
Accumulated OCI | $ | — |
| | $ | — |
| | $ | (42 | ) |
Regulatory assets (liabilities) | 40 |
| | (20 | ) | | 197 |
|
Total | $ | 40 |
| | $ | (20 | ) | | $ | 155 |
|
Balance at December 31, 2016: | | | | | |
Accumulated OCI | $ | — |
| | $ | — |
| | $ | (43 | ) |
Regulatory assets (liabilities) | — |
| | (2 | ) | | 269 |
|
Total | $ | — |
| | $ | (2 | ) | | $ | 226 |
|
Estimated amortization in net periodic cost in 2018: | | | | | |
Regulatory assets (liabilities) | $ | 3 |
| | $ | (2 | ) | | $ | 16 |
|
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for all periods presented were as follows: |
| | | | | | | |
| Accumulated OCI | | Regulatory Assets |
| (in millions) |
Predecessor – Balance at December 31, 2015: | $ | 282 |
| | $ | 88 |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | 1 |
| | — |
|
Amortization of net loss | (9 | ) | | (4 | ) |
Total reclassification adjustments | (8 | ) | | (4 | ) |
Total change | (8 | ) | | (4 | ) |
Predecessor – Balance at June 30, 2016: | $ | 274 |
| | $ | 84 |
|
| | | |
| | | |
Successor – Balance at July 1, 2016: | $ | — |
| | $ | 368 |
|
Net (gain) loss | (43 | ) | | (87 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | 1 |
|
Amortization of net loss | — |
| | (15 | ) |
Total reclassification adjustments | — |
| | (14 | ) |
Total change | (43 | ) | | (101 | ) |
Successor – Balance at December 31, 2016: | $ | (43 | ) | | $ | 267 |
|
Net (gain) loss | 1 |
| | (31 | ) |
Reclassification adjustments: | | | |
Amortization of regulatory assets | — |
| | (1 | ) |
Amortization of net loss | — |
| | (18 | ) |
Total reclassification adjustments | — |
| | (19 | ) |
Total change | 1 |
| | (50 | ) |
Successor – Balance at December 31, 2017: | $ | (42 | ) | | $ | 217 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Components of net periodic pension costs for all periods presented were as follows: |
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
| (in millions) | | | (in millions) |
Service cost | $ | 23 |
| | $ | 15 |
| | | $ | 13 |
| | $ | 28 |
|
Interest cost | 42 |
| | 20 |
| | | 21 |
| | 45 |
|
Expected return on plan assets | (70 | ) | | (35 | ) | | | (33 | ) | | (65 | ) |
Amortization of regulatory assets | 1 |
| | — |
| | | — |
| | — |
|
Amortization: | | | | | | | | |
Prior service costs | — |
| | (1 | ) | | | (1 | ) | | (2 | ) |
Net (gain)/loss | 18 |
| | 14 |
| | | 13 |
| | 31 |
|
Net periodic pension cost | $ | 14 |
| | $ | 13 |
| | | $ | 13 |
| | $ | 37 |
|
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets.
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 100 |
|
2019 | 77 |
|
2020 | 79 |
|
2021 | 79 |
|
2022 | 80 |
|
2023 to 2027 | 392 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Other Postretirement Benefits
Changes in the APBO and the fair value of plan assets for all periods presented were as follows:
|
| | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 |
| (in millions) | | | (in millions) |
Change in benefit obligation | | | | | | |
Benefit obligation at beginning of period | $ | 308 |
| | $ | 338 |
| | | $ | 318 |
|
Service cost | 2 |
| | 1 |
| | | 1 |
|
Interest cost | 10 |
| | 5 |
| | | 5 |
|
Benefits paid | (19 | ) | | (11 | ) | | | (11 | ) |
Actuarial (gain) loss | 3 |
| | (26 | ) | | | 24 |
|
Plan amendments | 3 |
| | — |
| | | — |
|
Employee contributions | 3 |
| | 1 |
| | | 1 |
|
Balance at end of period | 310 |
| | 308 |
| | | 338 |
|
Change in plan assets | | | | | | |
Fair value of plan assets at beginning of period | 105 |
| | 100 |
| | | 99 |
|
Actual return (loss) on plan assets | 20 |
| | 4 |
| | | 1 |
|
Employee contributions | 3 |
| | 1 |
| | | 1 |
|
Employer contributions | 17 |
| | 11 |
| | | 10 |
|
Benefits paid | (20 | ) | | (11 | ) | | | (11 | ) |
Fair value of plan assets at end of year | 125 |
| | 105 |
| | | 100 |
|
Accrued liability | $ | 185 |
| | $ | 203 |
| | | $ | 238 |
|
Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company's other postretirement benefit plans consist of the following:
|
| | | | | | | | |
| | 2017 | | 2016 |
| | (in millions) |
Other regulatory assets, deferred | | $ | 46 |
| | $ | 52 |
|
Employee benefit obligations | | (185 | ) | | (203 | ) |
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is immaterial. |
| | | | | | | | | | | |
| Regulatory Amortization | | Prior Service Cost | | Net (Gain) Loss |
| (in millions) |
Balance at December 31, 2017: | | | | | |
Accumulated OCI | $ | — |
| | $ | — |
| | $ | (3 | ) |
Regulatory assets (liabilities) | 6 |
| | (7 | ) | | 47 |
|
Total | $ | 6 |
| | $ | (7 | ) | | $ | 44 |
|
Balance at December 31, 2016: | | | | | |
Accumulated OCI | $ | — |
| | $ | — |
| | $ | (3 | ) |
Regulatory assets (liabilities) | — |
| | (12 | ) | | 64 |
|
Total | $ | — |
| | $ | (12 | ) | | $ | 61 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for all periods presented were as follows: |
| | | | | | | |
| Accumulated OCI | | Regulatory Assets |
| (in millions) |
Predecessor – Balance at December 31, 2015: | $ | 36 |
| | $ | 30 |
|
Net (gain) loss | — |
| | — |
|
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | 1 |
|
Amortization of net loss | (1 | ) | | (1 | ) |
Total reclassification adjustments | (1 | ) | | — |
|
Total change | (1 | ) | | — |
|
Predecessor – Balance at June 30, 2016: | $ | 35 |
| | $ | 30 |
|
| | | |
| | | |
Successor – Balance at July 1, 2016: | $ | — |
| | $ | 77 |
|
Net (gain) loss | (3 | ) | | (23 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | 1 |
|
Amortization of net loss | — |
| | (3 | ) |
Total reclassification adjustments | — |
| | (2 | ) |
Total change | (3 | ) | | (25 | ) |
Successor – Balance at December 31, 2016: | $ | (3 | ) | | $ | 52 |
|
Net (gain) loss | — |
| | (5 | ) |
Reclassification adjustments: | | | |
Amortization of prior service costs | — |
| | 3 |
|
Amortization of net loss | — |
| | (4 | ) |
Total reclassification adjustments | — |
| | (1 | ) |
Total change | — |
| | (6 | ) |
Successor – Balance at December 31, 2017: | $ | (3 | ) | | $ | 46 |
|
Components of the other postretirement benefit plans' net periodic cost for all periods presented were as follows: |
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
| (in millions) | | | (in millions) |
Service cost | $ | 2 |
| | $ | 1 |
| | | $ | 1 |
| | $ | 2 |
|
Interest cost | 10 |
| | 5 |
| | | 5 |
| | 13 |
|
Expected return on plan assets | (7 | ) | | (3 | ) | | | (3 | ) | | (7 | ) |
Amortization of regulatory assets | — |
| | 2 |
| | | — |
| | — |
|
Amortization: | | | | | | | | |
Prior service costs | (3 | ) | | — |
| | | (1 | ) | | (3 | ) |
Net (gain)/loss | 4 |
| | — |
| | | 2 |
| | 6 |
|
Net periodic postretirement benefit cost | $ | 6 |
| | $ | 5 |
| | | $ | 4 |
| | $ | 11 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. At December 31, 2017, estimated benefit payments were as follows:
|
| | | |
| Benefit Payments |
| (in millions) |
2018 | $ | 20 |
|
2019 | 20 |
|
2020 | 21 |
|
2021 | 21 |
|
2022 | 22 |
|
2023 to 2027 | 105 |
|
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets for each plan, is presented below:
|
| | | | | | | | | |
| | Target | | 2017 | | 2016 |
Pension plan assets: | | | | | | |
Equity | | 53 | % | | 65 | % | | 69 | % |
Fixed Income | | 15 |
| | 19 |
| | 20 |
|
Cash | | 2 |
| | 6 |
| | 1 |
|
Other | | 30 |
| | 10 |
| | 10 |
|
Balance at end of period | | 100 | % | | 100 | % | | 100 | % |
Other postretirement benefit plan assets: | | | | | | |
Equity | | 72 | % | | 76 | % | | 74 | % |
Fixed Income | | 24 |
| | 20 |
| | 23 |
|
Cash | | 1 |
| | 2 |
| | 1 |
|
Other | | 3 |
| | 2 |
| | 2 |
|
Total | | 100 | % | | 100 | % | | 100 | % |
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Investment Strategies
Detailed below is a description of the investment strategies for the successor period for each major asset category for the pension and other postretirement benefit plans disclosed above:
Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.
International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.
Fixed income. A mix of domestic and international bonds.
Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.
Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.
Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.
The investment strategies for the predecessor periods followed a policy to preserve the plans' capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans' assets were managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing the allocation policy for the assets of the pension and other postretirement benefit plans, the Company examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, the risk and return trade-offs of alternative asset classes and asset mixes were evaluated given long-term historical relationships as well as prospective capital market returns. The Company also conducted asset-liability studies to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. Asset mix guidelines were developed by incorporating the results of these analyses with an assessment of the Company's risk posture, and taking into account industry practices. The Company periodically evaluated its investment strategy to ensure that plan assets were sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, the Company made changes to its targeted asset allocations and investment strategy.
Benefit Plan Asset Fair Values
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2017 and 2016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation for the successor period, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:
Domestic and international equity.Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.
Fixed income.Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.
Real estate investments, private equity, and special situations investments.Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment. |
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 155 |
| | $ | 323 |
| | $ | — |
| | $ | — |
| | $ | 478 |
|
International equity(*) | — |
| | 166 |
| | — |
| | — |
| | 166 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 85 |
| | — |
| | — |
| | 85 |
|
Corporate bonds | — |
| | 39 |
| | — |
| | — |
| | 39 |
|
Cash equivalents and other | 84 |
| | 25 |
| | — |
| | 48 |
| | 157 |
|
Real estate investments | 3 |
| | — |
| | — |
| | 16 |
| | 19 |
|
Private equity | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | $ | 242 |
| | $ | 638 |
| | $ | — |
| | $ | 65 |
| | $ | 945 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 142 |
| | $ | 343 |
| | $ | — |
| | $ | — |
| | $ | 485 |
|
International equity(*) | — |
| | 185 |
| | — |
| | — |
| | 185 |
|
Fixed income: | | | | | | | | | |
U.S. Treasury, government, and agency bonds | — |
| | 85 |
| | — |
| | — |
| | 85 |
|
Corporate bonds | — |
| | 41 |
| | — |
| | — |
| | 41 |
|
Pooled funds | — |
| | 66 |
| | — |
| | — |
| | 66 |
|
Cash equivalents and other | 12 |
| | 5 |
| | — |
| | 83 |
| | 100 |
|
Real estate investments | 4 |
| | — |
| | — |
| | 15 |
| | 19 |
|
Private equity | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Total | $ | 158 |
| | $ | 725 |
| | $ | — |
| | $ | 100 |
| | $ | 983 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2017 and 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2017: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 3 |
| | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | 72 |
|
International equity(*) | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Fixed income: | | | | | | | | |
|
|
Pooled funds | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
Cash equivalents and other | 2 |
| | — |
| | — |
| | 1 |
| | 3 |
|
Total | $ | 5 |
| | $ | 115 |
| | $ | — |
| | $ | 1 |
| | $ | 121 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | | | |
| Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | Net Asset Value as a Practical Expedient | | |
As of December 31, 2016: | (Level 1) | | (Level 2) | | (Level 3) | | (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Domestic equity(*) | $ | 3 |
| | $ | 58 |
| | $ | — |
| | $ | — |
| | $ | 61 |
|
International equity(*) | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
Fixed income: | | | | | | | | | |
Pooled funds | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Cash equivalents and other | 1 |
| | — |
| | — |
| | 2 |
| | 3 |
|
Total | $ | 4 |
| | $ | 99 |
| | $ | — |
| | $ | 2 |
| | $ | 105 |
|
| |
(*) | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. |
Employee Savings Plan
SCS sponsors 401(k) defined contribution plans covering certain eligible Southern Company Gas employees. Through December 31, 2017, the 401(k) plans provided matching contributions of either 65% on up to 8% of an employee's eligible compensation, or a 100% matching contribution on up to 3% of an employee's eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee's eligible compensation. Total matching contributions made to the 401(k) plans for the successor periods ended December 31, 2017 and 2016 were $17 million and $8 million, respectively, and for the predecessor periods ended June 30, 2016 and December 31, 2015 were $10 million and $16 million, respectively.
For employees not accruing a benefit under the pension plan, additional contributions made to the 401(k) plans for the successor period ended December 31, 2017 were $2 million, for the successor period ended December 31, 2016 were not material, and for the predecessor periods ended June 30, 2016 and December 31, 2015 were $2 million for each period.
Effective January 1, 2018, the 401(k) plans were merged into the Southern Company Employee Savings Plan, which is a defined contribution plan covering substantially all employees of the Company. Under this plan, the Company matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee's base salary.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
3. CONTINGENCIES AND REGULATORY MATTERS
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of the Company, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and the Company's motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on the Company's financial statements.
The Company is assessing its alleged involvement in an incident that occurred in one of its service territories that resulted in several deaths, injuries, and property damage. One of the Company's utilities has been named as one of the defendants in several lawsuits related to this incident. The Company has insurance that provides full coverage of any financial exposure in excess of $11 million that is related to this incident. During the successor period ended December 31, 2016 and the predecessor period ended December 31, 2015, the Company recorded reserves for substantially all of its potential exposure from these cases. The ultimate outcome of this matter cannot be determined at this time.
The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements.
Environmental Matters
The Company's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations impact future results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each received authority from their applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms.
The Company is subject to environmental remediation liabilities associated with 46 former MGP sites in five different states. Accrued environmental remediation costs of $388 million and $426 million have been recorded in the balance sheets as of December 31, 2017 and 2016, respectively. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies, with the exception of one site representing $2 million of the accrued remediation costs.
In 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleged violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas distribution system and the EPA sought a total civil penalty of $0.3 million. On January 26, 2017, the EPA notified Nicor Gas that it agreed to voluntarily dismiss its administrative complaint with prejudice and without payment of a civil penalty or other further obligation on the part of Nicor Gas.
The Company's ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.
FERC Matters
At December 31, 2017, gas midstream operations was involved in two gas pipeline construction projects. These projects, along with the Company's existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
areas served. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval. On January 19, 2018, the PennEast Pipeline project received FERC approval.
Additionally, on August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced. See Note 4 for additional information.
Regulatory Matters
Regulatory Infrastructure Programs
The Company has infrastructure improvement programs at several of its utilities. Descriptions of these programs are as follows:
Nicor Gas
In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5%, of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, under which Nicor Gas implemented rates that became effective in March 2015.
Investing in Illinois is subject to annual review by the Illinois Commission. In conjunction with the base rate case order issued by the Illinois Commission on January 31, 2018, Nicor Gas is recovering the portion of these program costs incurred prior to December 31, 2017 through base rates. See "Base Rate Cases" herein for additional information.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which was initially approved by the Georgia PSC in 2009, is comprised of the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP), and the Integrated Vintage Plastic Replacement Program (i-VPR) and consists of infrastructure development, enhancement, and replacement programs that are used to update and expand distribution systems and LNG facilities, improve system reliability, and meet operational flexibility and growth. For 2017 and subsequent years, the recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.
The i-CGP program authorized Atlanta Gas Light to spend $91 million through 2017 on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. This program ended in 2017 and was replaced with a tariff to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.
The i-SRP program authorized $445 million of capital spending through 2017 for projects to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, improve its peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its i-SRP seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020.
The i-VPR program authorized Atlanta Gas Light to spend $275 million through 2017 to replace 756 miles of aging plastic pipe that was installed primarily in the mid-1960s to the early 1980s. Atlanta Gas Light has identified approximately 3,300 miles of vintage plastic mains in its system that should be considered for potential replacement.
See "Base Rate Cases" herein for additional information.
The orders for the STRIDE programs provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the programs net of any cost savings from the programs. The regulatory asset represents recoverable incurred costs related to the programs that will be collected in future rates charged to customers through the rate riders. The future expected costs to be recovered through rates related to allowed, but not incurred costs, are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the program. See "Unrecognized Ratemaking Amounts"herein for additional information.
Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operations and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operations and maintenance costs in excess of those included in its current base rates, depreciation, and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under recovered balance resulting from the timing difference.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Elizabethtown Gas
Elizabethtown Gas' 2013 extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65%. Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See "Base Rate Cases" herein for additional information.
In 2015, Elizabethtown Gas filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, Elizabethtown Gas withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In 2012, the Virginia Commission approved the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program, to be completed over a five-year period. This program included a maximum allowance for capital expenditures of $25 million per year, not to exceed $105 million in total.
In March 2016, the Virginia Commission approved an extension to the SAVE program for Virginia Natural Gas to replace more than 200 miles of aging pipeline infrastructure and invest up to $30 million in 2016 and up to $35 million annually through 2021.
The SAVE program is subject to annual review by the Virginia Commission. In conjunction with the base rate case order issued by the Virginia Commission on December 21, 2017, Virginia Natural Gas is recovering the portion of these program costs incurred prior to September 1, 2017 through base rates. See "Base Rate Cases" herein for additional information.
Florida City Gas
In 2015, the Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program, under which costs incurred for replacing aging pipes are recovered through a rate rider with annual adjustments and true-ups. Under the program, Florida City Gas is authorized to spend $105 million over a 10-year period on infrastructure relocation and enhancement projects.
PRP Settlement
In 2015, Atlanta Gas Light received a final order from the Georgia PSC for a rate true-up of allowed unrecovered revenue through 2014 related to its PRP. This order allows Atlanta Gas Light to recover $144 million of the $178 million previously unrecovered program revenue. The remaining $34 million requested related primarily to previously unrecognized ratemaking amounts and did not have a material impact on the Company's financial statements. The Company also recognized $1 million of interest expense and $5 million in operations and maintenance expense related to the PRP on the Company's statements of income for the predecessor year ended December 31, 2015. See "Unrecognized Ratemaking Amounts"herein for additional information.
As a result of the PRP settlement, Atlanta Gas Light began recovering incremental PRP surcharge amounts through three phased in increases in addition to its previously existing PRP surcharge amount, which was established to address recovery of the unrecovered PRP balance of $144 million in 2015 and the estimated amounts to be earned under the program through 2025. The initial incremental surcharge of approximately $15 million annually was effective in October 2015, with additional annual increases of approximately $15 million in each of October 2016 and 2017. The final increase scheduled for October 2017 was included in the implementation of GRAM in March 2017. The under recovered balance is the result of the continued revenue requirement earned under the program offset by the existing and incremental PRP surcharges. The unrecovered balance at December 31, 2017 was $187 million, including $104 million of unrecognized equity return. The PRP surcharge will remain in effect until the earlier of the full recovery of the under recovered amount or December 31, 2025. See "Base Rate Cases" herein for additional information on GRAM.
One of the capital projects under the PRP experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. These mitigation costs will be included in future base rates in 2018. Provisions in the order resulted in the recognition of $5 million in operations and maintenance expense for the predecessor year ended December 31, 2015 on the Company's statements of income. In 2017, Atlanta Gas Light recovered $20 million from the settlement of contractor litigation claims and continues to pursue contractual and legal claims against a third-party contractor. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. The ultimate outcome of this matter cannot be determined at this time.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Base Rate Cases
Settled Base Rate Cases
On February 21, 2017, the Georgia PSC approved GRAM and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, using an earnings band based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Atlanta Gas Light adjusts rates up to
the lower end of the band of 10.55% and adjusts rates down to the higher end of the band of 10.95%. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the i-VPR and i-SRP, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the i-CGP that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.
Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.
On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the proposed sale of Elizabethtown Gas.
On December 21, 2017, the Virginia Commission approved a settlement for a $34 million increase in annual base rate revenues, effective September 1, 2017, including $13 million related to the recovery of investments under the SAVE program. See "Regulatory Infrastructure Programs" herein for additional information. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates.
On January 31, 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective February 8, 2018, based on a ROE of 9.8%.
Pending Base Rate Cases
On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. On January 29, 2018, Florida City Gas filed an update to incorporate the effects of the Tax Reform Legislation that, if approved, would reduce the requested base rate revenues by $4 million. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under SAFE that are currently being recovered through a surcharge. Additionally, Florida City Gas requested an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.
On December 1, 2017, Atlanta Gas Light filed its 2018 annual rate adjustment with the Georgia PSC. If approved, annual base rate revenues will increase by $22 million, effective June 1, 2018. Atlanta Gas Light will file a revised rate adjustment to incorporate the effects of the Tax Reform Legislation in the first quarter 2018. The Georgia PSC is expected to rule on the revised requested increase in the second quarter 2018.
On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission requesting a $7 million increase in annual base rate revenues. The requested increase, which incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee Public Utility Commission is expected to rule on the requested increase in the third quarter 2018.
The ultimate outcome of these pending base rate cases cannot be determined at this time.
Other
The New Jersey BPU, Virginia Commission, Tennessee Public Utility Commission, and Maryland PSC each issued an order effective January 1, 2018 that requires utilities in their respective states to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
taxes. The New Jersey BPU's order requires Elizabethtown Gas to file by March 2, 2018 proposed revised base rates with an April 1, 2018 interim effective date and a July 1, 2018 final effective date. Virginia Natural Gas will address the Virginia Commission's order in its Annual Information Filing, which will be filed by July 1, 2018. The Tennessee Public Utility Commission's order required Chattanooga Gas to file proposals to reduce rates or make other ratemaking adjustments to account for the impact of the Tax Reform Legislation. Chattanooga Gas made the required filing as part of its February 15, 2018 general base rate case filing. The Maryland PSC's order required Elkton Gas to file an explanation of the impact of the Tax Reform Legislation on its expenses and revenues, as well as when and how it expects to pass through to its customers those effects. Elkton Gas made the required filing on February 15, 2018 and will reduce annual base rates by $0.1 million effective April 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018.
The Illinois Commission issued an order effective January 25, 2018 that requires utilities in the state to record the impacts of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes, as a regulatory liability. On February 20, 2018, the Illinois Commission granted Nicor Gas' application for rehearing to file revised base rates and tariffs, which Nicor Gas expects to file by the end of the second quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
energySMART
In 2014, the Illinois Commission approved Nicor Gas' energySMART through 2017, which outlined energy efficiency program offerings and therm reduction goals, and subsequently extended the program to 2021. Through December 31, 2017, Nicor Gas spent $107 million of the initial authorized expenditure of $113 million. A new four-year program began on January 1, 2018, with an additional authorized expenditure of $160 million.
Unrecognized Ratemaking Amounts
The following table illustrates the Company's authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain of the Company's regulatory infrastructure programs. These amounts will be recognized as revenues in the Company's financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.
|
| | | | | | | |
| December 31, 2017 | | December 31, 2016 |
| (in millions) |
Atlanta Gas Light | $ | 104 |
| | $ | 110 |
|
Virginia Natural Gas | 11 |
| | 11 |
|
Elizabethtown Gas(*) | 8 |
| | 6 |
|
Nicor Gas | 2 |
| | 2 |
|
Total | $ | 125 |
| | $ | 129 |
|
(*) See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for information on the pending asset sale.
Other Matters
A wholly-owned subsidiary of the Company owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in the Company retiring the cavern early. At December 31, 2017, the facility's property, plant, and equipment had a net book value of $112 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. These events were considered in connection with the Company's annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2017. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on the Company's financial statements.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
4. JOINT OWNERSHIP AGREEMENTS
In 2014, the Company entered into a construction and ownership arrangement associated with the Dalton Pipeline through which the Company has a 50% undivided ownership interest jointly with The Williams Companies, Inc. in the 115-mile Dalton Pipeline to serve as an extension of the Transco natural gas pipeline system into northwest Georgia. The Company also entered into an agreement to lease its 50% undivided ownership in the Dalton Pipeline that became effective when it was placed in service on August 1, 2017. Under the lease, the Company will receive approximately $26 million annually for an initial term of 25 years. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. At December 31, 2017, the net book value of the Company's 50% share of the pipeline was $252 million and is reflected in total property, plant, and equipment in the balance sheet. At December 31, 2016, the net book value of the Company's 50% share of the pipeline was $124 million and is reflected in construction work in progress in the balance sheet.
Variable Interest Entities
SouthStar, previously a joint venture owned 85% by the Company and 15% by Piedmont, was the only VIE for which the Company was the primary beneficiary, prior to October 2016 when the Company completed its purchase of Piedmont's remaining interest in SouthStar.
In 2015, Georgia Natural Gas Company (GNG), a 100%-owned, direct subsidiary of the Company, notified Piedmont of its election, pursuant to a change in control of SouthStar, to purchase Piedmont's 15% interest in SouthStar at fair market value. This purchase was contingent upon the closing of the merger between Piedmont and Duke Energy Corporation (Duke Energy). In October 2016, after Piedmont and Duke Energy completed their merger, GNG completed its purchase of Piedmont's interest in SouthStar and paid a purchase price of $160 million and $15 million for Piedmont's share of SouthStar's 2016 earnings through the date of acquisition.
At December 31, 2015, the Company presented the noncontrolling interest related to Piedmont's interest in SouthStar as a component in equity. During the first quarter 2016, the Company reclassified its noncontrolling interest, whose redemption was beyond the Company's control, as a contingently redeemable noncontrolling interest. Upon Piedmont and Duke Energy obtaining the necessary merger approval, the Company deemed this noncontrolling interest to be mandatorily redeemable and reclassified it to a current liability during the third quarter 2016. The roll-forwards of the redeemable noncontrolling interest for the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 are detailed below:
|
| | | |
Predecessor – | (in millions) |
Balance at December 31, 2015 | $ | — |
|
Reclassification of noncontrolling interest to contingently redeemable noncontrolling interest | 46 |
|
Net income attributable to noncontrolling interest | 14 |
|
Distribution to noncontrolling interest | (19 | ) |
Balance at June 30, 2016 | $ | 41 |
|
Successor – | (in millions) |
Balance at July 1, 2016 | $ | 174 |
|
Reclassification of contingently redeemable noncontrolling interest to mandatorily redeemable noncontrolling interest | (174 | ) |
Balance at December 31, 2016 | $ | — |
|
The Company's cash flows used for financing activities included SouthStar's distribution to Piedmont for its portion of SouthStar's annual earnings from the previous year, which generally occurred in the first quarter of each year. For the successor period of July 1, 2016 through December 31, 2016, SouthStar made a distribution of $15 million upon completion of the purchase of Piedmont's interest in SouthStar. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, SouthStar distributed to Piedmont $19 million and $18 million, respectively.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Equity Method Investments
The carrying amounts of the Company's equity method investments as of December 31, 2017 and 2016 and related income from those investments for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows:
|
| | | | | | | | |
Balance Sheet Information | December 31, 2017 | | | December 31, 2016 |
| (in millions) |
SNG(*) | $ | 1,262 |
| | | $ | 1,394 |
|
Triton | 42 |
| | | 44 |
|
Horizon Pipeline | 30 |
| | | 30 |
|
PennEast Pipeline | 57 |
| | | 22 |
|
Atlantic Coast Pipeline | 41 |
| | | 33 |
|
Pivotal JAX LNG, LLC | 44 |
| | | 16 |
|
Other | 1 |
| | | 2 |
|
Total | $ | 1,477 |
| | | $ | 1,541 |
|
| |
(*) | Includes a $104 million decrease at December 31, 2017 related to the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. |
|
| | | | | | | | | | | | | | | | |
| Successor | | Predecessor |
Income Statement Information | Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
| (in millions) | | (in millions) |
SNG | $ | 88 |
| | $ | 56 |
| | | $ | — |
| | $ | — |
|
Triton | 4 |
| | 2 |
| | | 1 |
| | 4 |
|
Horizon Pipeline | 2 |
| | 1 |
| | | 1 |
| | 2 |
|
Atlantic Coast Pipeline | 6 |
| | 1 |
| | | — |
| | — |
|
PennEast Pipeline | 6 |
| | — |
| | | — |
| | — |
|
Total | $ | 106 |
| | $ | 60 |
| | | $ | 2 |
| | $ | 6 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
SNG
In September 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. See Note 11 under "Investment in SNG" for additional information. Selected financial information of SNG as of December 31, 2017 and 2016 and for the year ended December 31, 2017 and for the period September 1, 2016 through December 31, 2016 is as follows:
|
| | | | | | | |
| As of December 31, |
Balance Sheet Information | 2017 | | 2016 |
| (in millions) |
Current assets | $ | 82 |
| | $ | 95 |
|
Property, plant, and equipment | 2,439 |
| | 2,451 |
|
Deferred charges and other assets | 121 |
| | 129 |
|
Total Assets | $ | 2,642 |
| | $ | 2,675 |
|
| | | |
Current liabilities | $ | 110 |
| | $ | 588 |
|
Long-term debt | 1,102 |
| | 706 |
|
Other deferred charges and other liabilities | 76 |
| | 22 |
|
Total Liabilities | $ | 1,288 |
| | $ | 1,316 |
|
| | | |
Total Stockholders' Equity | 1,354 |
| | 1,359 |
|
Total Liabilities and Stockholders' Equity | $ | 2,642 |
| | $ | 2,675 |
|
|
| | | | | | | |
Income Statement Information | Year ended December 31, 2017 | | September 1, 2016 through December 31, 2016 |
| (in millions) |
Revenues | $ | 544 |
| | $ | 230 |
|
Operating income | 246 |
| | 138 |
|
Net income | $ | 175 |
| | $ | 115 |
|
Other Investments
Triton
The Company has an investment in Triton, a cargo container leasing company, which is aggregated into its all other segment. Container equipment that is acquired by Triton is accounted for in tranches as defined in Triton's operating agreement and investors make capital contributions to Triton to invest in each of the tranches. As of December 31, 2017, the Company had invested in seven tranches established by Triton.
Horizon Pipeline
The Company owns aninterest in a joint venture with Natural Gas Pipeline Company of America that is regulated by the FERC. Horizon Pipeline operates a 70-mile natural gas pipeline from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas typically contracts for 70% to 80% of the total annual capacity.
PennEast Pipeline
In 2014, the Company entered into a partnership in which it holds a 20% ownership interest in an interstate pipeline company formed to develop and operate a 118-mile natural gas pipeline between New Jersey and Pennsylvania. The initial transportation capacity of 1.0 billion cubic feet (Bcf) per day, is under long-term contracts, mainly by public utilities and other market-serving entities, such as electric generation companies, in New Jersey, Pennsylvania, and New York. On January 19, 2018, the PennEast Pipeline project received FERC approval.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Atlantic Coast Pipeline
In 2014, the Company entered into a project in which it holds a 5% ownership interest in an interstate pipeline company formed to develop and operate a 594-mile natural gas pipeline in North Carolina, Virginia, and West Virginia with initial transportation capacity of 1.5 Bcf per day. On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.
Pivotal JAX LNG, LLC
The Company owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.
5. INCOME TAXES
Subsequent to the Merger, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns on behalf of the Company. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company filed a U.S. federal consolidated income tax return and various state income tax returns.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
|
| | | | | | | | | | | | | | | | |
| Successor | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
| (in millions) | | (in millions) |
Federal — | | | | | | | | |
Current | $ | 103 |
| | $ | — |
| | | $ | 67 |
| | $ | (13 | ) |
Deferred | 170 |
| | 65 |
| | | 8 |
| | 198 |
|
| 273 |
| | 65 |
| | | 75 |
| | 185 |
|
State — | | | | | | | | |
Current | 27 |
| | (16 | ) | | | 12 |
| | 10 |
|
Deferred | 67 |
| | 27 |
| | | — |
| | 18 |
|
| 94 |
| | 11 |
| | | 12 |
| | 28 |
|
Total | $ | 367 |
| | $ | 76 |
| | | $ | 87 |
| | $ | 213 |
|
Net cash payments (refunds) for income taxes for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were $72 million, $23 million, $(100) million, and $(26) million, respectively.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (in millions) |
Deferred tax liabilities — | | | |
Accelerated depreciation | $ | 1,436 |
| | $ | 1,954 |
|
Property basis differences | 204 |
| | 311 |
|
Regulatory assets associated with employee benefit obligations | 79 |
| | 125 |
|
Other | 208 |
| | 164 |
|
Total | 1,927 |
| | 2,554 |
|
Deferred tax assets — | | | |
Federal net operating loss | 92 |
| | 59 |
|
Federal effect of state deferred taxes | 54 |
| | 42 |
|
Employee benefit obligations | 185 |
| | 165 |
|
Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 295 |
| | — |
|
Other | 223 |
| | 332 |
|
Total | 849 |
| | 598 |
|
Less valuation allowances | (11 | ) | | (19 | ) |
Total, net of valuation allowances | 838 |
| | 579 |
|
Accumulated deferred income taxes, net | $ | 1,089 |
| | $ | 1,975 |
|
The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by
bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly increased tax-related regulatory liabilities.
At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $1.1 billion. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.
Deferred federal and state ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $4 million and $1 million for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and for the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, were $1 million and $2 million, respectively. At December 31, 2017, all ITCs available to reduce federal income taxes payable had been utilized.
Effective Tax Rate
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
|
| | | | | | | | |
| Successor | | | Predecessor |
| Year ended December 31, 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Year ended December 31, 2015 |
Federal statutory rate | 35.0% | | 35.0% | | | 35.0% | | 35.0% |
State income tax, net of federal deduction | 4.0 | | 4.0 | | | 3.5 | | 3.4 |
Tax Reform Legislation | 15.0 | | — | | | — | | — |
State tax legislation and rate changes | 6.2 | | — | | | — | | — |
Other | — | | 1.0 | | | (0.9) | | (2.0) |
Effective income tax rate | 60.2% | | 40.0% | | | 37.6% | | 36.4% |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The principal differences in the Company's effective tax rate from December 31, 2016 to December 31, 2017 include the impact of the Tax Reform Legislation, the Illinois income tax legislation enacted in the third quarter 2017, new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings, the disallowance of certain nondeductible Merger-related expenses associated with change-in-control compensation charges, and an increase in earnings before income taxes.
Unrecognized Tax Benefits
The Company has no unrecognized tax benefits for any period presented.
The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any period presented.
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
On July 1, 2016, the Company became a wholly-owned subsidiary of Southern Company, which is a participant in the Compliance Assurance Process of the IRS. The IRS has finalized its audits of Southern Company's consolidated federal tax returns through 2016. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for the Company by any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for years prior to 2011.
6. FINANCING
The Company's 100%-owned subsidiary, Southern Company Gas Capital, was established to provide for certain of the Company's ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital and the gas facility revenue bonds issued by Pivotal Utility Holdings. Additionally, substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs.
Securities Due Within One Year
The current portion of long-term debt is composed of the portion of its long-term debt due within the next 12 months. At December 31, 2017, the Company had $157 million of senior notes due within one year, including the fair value adjustment attributable to the application of acquisition accounting. At December 31, 2016, the Company had $22 million of medium-term notes due within one year.
Long-Term Debt
Long-term debt of the Company at December 31, 2017 and 2016 consisted of Series A, Series B, and Series C medium-term notes of Atlanta Gas Light; senior notes of Southern Company Gas Capital; first mortgage bonds of Nicor Gas; and gas facility revenue bonds of Pivotal Utility Holdings.
Maturities through 2022 applicable to total long-term debt are as follows: $155 million in 2018; $350 million in 2019; $330 million in 2021; $93 million in 2022; and $4.6 billion thereafter. There are no material scheduled maturities in 2020.
Medium-Term Notes
In July 2017, Atlanta Gas Light repaid at maturity $22 million of medium-term notes. The amount of medium-term notes outstanding at December 31, 2017 and 2016 was $159 million and $181 million, respectively, including securities due within one year.
Senior Notes
In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay the Company's short-term indebtedness and for general corporate purposes. The amount of senior notes outstanding at December 31, 2017 and 2016 was $4.2 billion and $3.7 billion, respectively, including securities due within one year.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
First Mortgage Bonds
Nicor Gas had $1.0 billion and $625 million of first mortgage bonds outstanding at December 31, 2017 and 2016, respectively. These bonds have been issued with maturities ranging from 2019 to 2057.
On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. On November 1, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.85% Series due August 10, 2047 and $100 million aggregate principal amount of First Mortgage Bonds 4.00% Series due August 10, 2057. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.
Gas Facility Revenue Bonds
Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds have been issued with maturities ranging from 2022 to 2033. These revenue bonds are issued by state agencies or counties to investors, and proceeds from each issuance then are loaned to Pivotal Utility Holdings. The amount of gas facility revenue bonds outstanding at December 31, 2017 and 2016 was $200 million.
The Elizabethtown Gas asset sale agreement requires that bonds representing $180 million of the total that are currently eligible for redemption at par be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 11 under "Proposed Sale of Elizabethtown Gas and Elkton Gas" for additional information.
Parent Company Note
On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million due July 31, 2018, bearing interest based on one-month LIBOR.
Dividend Restrictions
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. The New Jersey BPU restricts the amount Elizabethtown Gas can dividend to its parent company to 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, the Company is prohibited from paying dividends to its parent company, Southern Company, if the Company's senior unsecured debt rating falls below investment grade. As of December 31, 2017, the amount of subsidiary retained earnings restricted for dividend payment totaled $719 million.
Bank Credit Arrangements
Credit Facilities
At December 31, 2017, committed credit arrangements with banks were as follows:
|
| | | | | | | | |
Company | | Expires 2022 | | Unused |
| | (in millions) |
Southern Company Gas Capital | | $ | 1,400 |
| | $ | 1,390 |
|
Nicor Gas | | 500 |
| | 500 |
|
Total | | $ | 1,900 |
| | $ | 1,890 |
|
In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.4 billion and $500 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% for each of the Company and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if the Company or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2017, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Commercial Paper Programs
The Company maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas that consist of short-term, unsecured promissory notes. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of the Company's other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. Commercial paper is included in notes payable in the balance sheets.
Details of commercial paper borrowings outstanding were as follows: |
| | | | | | | |
| | Short-term Debt at the End of the Period |
| | Amount Outstanding | | Weighted Average Interest Rate |
| | (in millions) | | |
December 31, 2017: | | | | |
Southern Company Gas Capital | | $ | 1,243 |
| | 1.73 | % |
Nicor Gas | | 275 |
| | 1.83 |
|
Total | | $ | 1,518 |
| | 1.75 | % |
| | | | |
December 31, 2016: | | | | |
Southern Company Gas Capital | | $ | 733 |
| | 1.09 | % |
Nicor Gas | | 524 |
| | 0.95 |
|
Total | | $ | 1,257 |
| | 1.03 | % |
7. COMMITMENTS
Pipeline Charges, Storage Capacity, and Gas Supply
Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to Marketers and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas' and SouthStar's gas commodity purchase commitments of 35 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2017 and valued at $101 million. The Company provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.
Expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets as of December 31, 2017 were as follows:
|
| | | |
| Pipeline Charges, Storage Capacity, and Gas Supply |
| (in millions) |
2018 | $ | 813 |
|
2019 | 552 |
|
2020 | 416 |
|
2021 | 375 |
|
2022 | 339 |
|
2023 and thereafter | 2,294 |
|
Total | $ | 4,789 |
|
Operating Leases
The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $15 million, $8 million, $6 million, and $12 million for the successor periods of the year ended December 31, 2017 and July 1, 2016 through December 31, 2016 and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, respectively. The Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease terms.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
As of December 31, 2017, the Company's estimated minimum lease payments under operating leases were as follows:
|
| | | |
| Minimum Lease Payments |
| (in millions) |
2018 | $ | 17 |
|
2019 | 16 |
|
2020 | 16 |
|
2021 | 15 |
|
2022 | 13 |
|
2023 and thereafter | 26 |
|
Total | $ | 103 |
|
Financial Guarantees
AGL Equipment Leasing Inc. (AEL), a wholly-owned subsidiary of the Company, holds the Company's interest in Triton and has an obligation to restore to zero any deficit in its equity account for income tax purposes in the unlikely event that Triton is liquidated and a deficit balance remains. This obligation continues for the life of the Triton partnerships. Any payment is effectively limited to the net assets of AEL, which were less than $1 million at December 31, 2017. The Company believes the likelihood of any such payment by AEL is remote and, as such, no liability has been recorded for this obligation at December 31, 2017.
8. STOCK COMPENSATION
Successor
Stock-Based Compensation
Stock-based compensation primarily in the form of Southern Company performance share units and restricted stock units may be granted through the Omnibus Incentive Compensation Plan to certain levels of management within the Company. In 2017, stock-based compensation granted to employees includes performance share units and restricted stock units. In 2016, in conjunction with the Merger, stock-based compensation was granted to certain executives in the form of Southern Company restricted stock and performance share units. As of December 31, 2017, there were 327 current and former employees participating in the performance share unit and restricted stock unit programs.
Performance Share Units
Performance share units granted to employees vest at the end of a three-year performance period. All unvested performance share units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of performance share units granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
Southern Company issues performance share units with performance goals based on three performance goals to employees. These include performance share units with performance goals based on the total shareholder return (TSR) for Southern Company common stock during the three-year performance period as compared to a group of industry peers, performance share units with performance goals based on Southern Company's cumulative earnings per share (EPS) over the performance period, and performance share units with performance goals based on Southern Company's equity-weighted ROE over the performance period.
The total target grant date fair value of the stock compensation awards granted was comprised 20% each of EPS-based awards and ROE-based awards and 30% each of TSR-based awards and restricted stock units.
The fair value of TSR-based performance share unit awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's common stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of the EPS-based awards and the ROE-based awards are based on the closing stock price of Southern Company common stock on the date of the grant. Compensation expense for the EPS-based and ROE-based awards is generally recognized ratably over the three-year performance period initially assuming a 100% payout at the end of the performance period. Employees
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
become immediately vested in the TSR-based performance share units, along with the EPS-based and ROE-based awards, upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. The expected payout related to the EPS-based and ROE-based awards is reevaluated annually with expense recognized to date increased or decreased based on the number of shares currently expected to be issued. Unlike the TSR-based awards, the compensation expense ultimately recognized for the EPS-based awards and the ROE-based awards will be based on the actual number of shares issued at the end of the performance period.
For the year ended December 31, 2017, employees of the Company were granted 0.3 million performance share units. The weighted average grant-date fair value of TSR-based performance share units granted during 2017, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $49.27. The weighted average grant-date fair value of both EPS-based and ROE-based performance share units granted during 2017 was $49.22.
For the year ended December 31, 2017, total compensation cost for performance share units recognized in income was $8 million with the related tax benefit also recognized in income of $3 million. The compensation cost related to the grant of Southern Company performance share units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017, $6 million of total unrecognized compensation cost related to performance share award units will be recognized over a weighted-average period of approximately 21 months.
Restricted Stock Units
Stock-based compensation granted to employees included restricted stock units in addition to performance share units. One-third of the restricted stock units granted to employees vest each year throughout a three-year service period. All unvested restricted stock units vest immediately upon a change in control where Southern Company is not the surviving corporation. Shares of Southern Company common stock are delivered to employees at the end of the vesting period.
The fair value of restricted stock units is based on the closing stock price of Southern Company common stock on the date of the grant. Since one-third of the restricted stock units vest each year throughout a three-year service period, compensation expense for restricted stock unit awards is generally recognized over the corresponding one-, two-, or three-year period. Employees become immediately vested in the restricted stock units upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility.
For the year ended December 31, 2017, employees of the Company were granted 0.1 million restricted stock units. The weighted average grant-date fair value of restricted stock units granted during 2017 was $49.23.
For the year ended December 31, 2017, total compensation cost for restricted stock units recognized in income was $4 million with the related tax benefit also recognized in income of $2 million. The compensation cost related to the grant of Southern Company restricted stock units to the Company's employees is recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2017, $1 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 13 months.
Merger Stock Compensation
At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger:
Southern Company Gas' outstanding restricted stock units, restricted stock awards, and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share;
Southern Company Gas' outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options; and
each outstanding award of a performance share unit was converted into an award of Southern Company's restricted stock units (restricted stock awards).
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
In conjunction with the Merger, stock-based compensation, in the form of Southern Company restricted stock and performance share units, was granted to certain executives of the Company through the Southern Company Omnibus Incentive Compensation Plan.
Southern Company Restricted Stock Awards
Under the terms of the restricted stock awards, the employees received a specified number of restricted stock units that vest when the employees have satisfied the requisite service period(s) at which time the employee receives Southern Company common stock. The terms of the award require the employee to be continuously employed through the original three-year vesting schedule of the award being replaced.
For the successor period ended December 31, 2016, employees of the Company were granted 0.7 million restricted stock units. The grant-date fair value of the restricted stock units granted was $53.83, based on the closing stock price of Southern Company common stock on the date of the grant. As a portion of the fair value of the award related to pre-combination service, the grant date fair value was allocated to pre- or post-combination service and accounted for as Merger consideration or compensation cost, respectively. Approximately $13 million of the grant date fair value was allocated to Merger consideration. The remaining fair value of $12 million is being recognized as compensation expense on a straight-line basis over the remaining vesting period.
The compensation cost related to the grant of restricted stock units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, total compensation cost for restricted stock units recognized in income was $8 million and $13 million, respectively, with the related tax benefit also recognized in income of $4 million and $4 million, respectively. As of December 31, 2017, $3 million of total unrecognized compensation cost related to restricted stock units will be recognized over a weighted-average period of approximately 12 months. See "Performance Share Unit Awards" herein for additional information.
Change in Control Awards
Southern Company awarded performance share units to certain employees remaining with the Company in lieu of certain change in control benefits the employee was entitled to receive following the Merger (change-in-control awards). Shares of Southern Company common stock and/or cash equal to the dollar value of the change-in-control benefit will vest and be issued one-third each year as long as the employee remains in service with the Company, or any of its affiliates, at each vest date. In addition to the change-in-control benefit, Southern Company common stock could be issued to the employees at the end of a performance period with the number of shares issued ranging from 0% to 100% of the target number of performance share units granted, based on achievement of certain Southern Company common stock price metrics, as well as performance goals established by the Compensation Committee of the Southern Company Board of Directors (achievement shares).
The change-in-control benefits are accounted for as a liability award with the fair value equal to the guaranteed dollar value of the change-in-control benefit. The grant-date fair value of the achievement portion of the award was determined using a Monte Carlo simulation model to estimate the number of achievement shares expected to vest based on the Southern Company common stock price. The expected payout is reevaluated annually with expense recognized to date increased or decreased proportionately based on the expected performance. The compensation expense ultimately recognized for the achievement shares will be based on the actual performance.
For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, total compensation cost for the change-in-control awards recognized in income was $12 million and $4 million, respectively, with $6 million and less than $1 million, respectively, of related tax benefit recognized in income. The compensation cost related to the grant of Southern Company change-in-control benefit and achievement shares to the Company's employees are recognized in the Company's financial statements with a corresponding credit to a liability or equity, representing a capital contribution from Southern Company, respectively. As of December 31, 2017, $8 million of total unrecognized compensation cost related to change in control awards will be recognized over a weighted-average period of approximately 18 months.
Predecessor
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, the employees of Southern Company Gas and subsidiaries participated in the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated.
The AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated, and the Long-Term Incentive Plan (1999) provided for the grant of incentive and nonqualified stock options, stock appreciation rights, shares of restricted stock, restricted stock units, performance cash awards, and other stock-based awards to officers and key employees. Effective July 1, 2016, all Southern Company Gas shares of stock were canceled and/or converted as a result of the Merger. No further grants will
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
be made from the Long-Term Incentive Plan (1999) or the AGL Resources Inc. Omnibus Performance Incentive Plan, as amended and restated.
For the predecessor periods, the Company recognized stock-based compensation expense for its stock-based awards over the requisite service period based on the estimated fair value at the date of grant for its stock-based awards using the modified prospective method. These stock awards included: stock options, stock and restricted stock awards, and performance units (restricted stock units, performance share units, and performance cash units).
Performance-based stock awards and performance units contained market and performance conditions. Stock options, restricted stock awards, and performance units also contained a service condition. The Company estimated forfeitures over the requisite service period when recognizing compensation expense. These estimates were adjusted to the extent that actual forfeitures differ, or were expected to materially differ, from such estimates. Excess tax benefits were reported as a financing cash inflow. The difference between the proceeds from the exercise of the Company's stock-based awards and the par value of the stock was recorded within additional paid-in capital.
Southern Company Gas granted stock awards with a grant price that was equal to the fair market value on the date of the grant. Fair market value was defined under the terms of the applicable plans as the closing price per share of Southern Company Gas' common stock on the grant date. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, total compensation cost for cash and stock-based awards recognized in income was $24 million and $40 million, respectively, with related tax benefits also recognized in income, which were immaterial.
Incentive and Nonqualified Stock Options
The stock options that the Company granted prior to the Merger had a three-year vesting period and expired ten years after the date of grant. The exercise price for stock options granted equaled the stock price of Southern Company Gas common stock on the date of grant. Participants realized value from option grants only to the extent that the fair market value of the Company's common stock on the date of exercise of the option exceeded the fair market value of the common stock on the date of the grant. No stock options have been issued under the plan since 2009.
The Company measured compensation cost related to stock options based on the fair value of these awards at their date of grant using the Black-Scholes option-pricing model. For the predecessor year ended December 31, 2015, the Company had no unrecognized compensation costs related to stock options. For the predecessor period ended June 30, 2016 and the year ended December 31, 2015, cash received from stock option exercises and the related income tax benefits were immaterial.
For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, the total intrinsic value of options exercised was $3 million, and $13 million, respectively.
Effective July 1, 2016, all of the Company's outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such options and (ii) the excess of the Merger consideration of $66 per share over the applicable exercise price per share of such options.
Restricted Stock Units
A restricted stock unit is an award that represents the opportunity to receive a specified number of shares of the Company's common stock, subject to the achievement of certain pre-established performance criteria. For the predecessor period of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, the Company granted 25,166 and 47,546, respectively, of restricted stock units (including dividends) to certain employees. At the effective time of the Merger, all restricted stock units outstanding were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share.
Performance Share Unit Awards
A performance share unit award represented the opportunity to receive cash and shares subject to the achievement of certain pre-established performance criteria. For the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015, the Company granted performance share unit awards to certain officers. The Company's 2016 and 2015 performance share units had two performance measures. One measure, which accounted for 75%, related to the Company's total shareholder return relative to a group of peer companies. The second measure, which accounted for 25%, related to the Company's earnings per share, excluding wholesale gas services, over the three-year performance period.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
At the effective time of the Merger, each outstanding performance share unit was converted into an award of Southern Company's restricted stock units. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the Merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock. The resulting Southern Company restricted stock units will follow the vesting schedule and payment terms, and otherwise be issued on similar terms and conditions, as were applicable to such pre-Merger performance share unit awards, subject to certain exceptions. See "Southern Company Restricted Stock Awards" for additional information.
Stock and Restricted Stock Awards
The compensation cost of both stock awards and restricted stock awards was equal to the grant date fair value of the awards, recognized over the requisite service period. No other assumptions were used to value the awards. The Company referred to restricted stock as an award of Company common stock subject to time-based vesting or achievement of performance measures. Prior to vesting, restricted stock awards were subject to certain transfer restrictions and forfeiture upon termination of employment.
Restricted Stock Awards—Employees
Total unvested restricted stock awards outstanding as of December 31, 2015 totaled 0.4 million. During 2016, 0.3 million restricted stock awards were granted, 0.7 million restricted stock awards were vested or forfeited. At the effective time of the Merger, Southern Company Gas' outstanding restricted stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of Southern Company Gas' common stock subject to such award and (ii) the Merger consideration of $66 per share.
9. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. See Note 1 under "Fair Value Measurements" for additional information on the fair value hierarchy.
As of December 31, 2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
As of December 31, 2017: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 331 |
| | $ | 223 |
| | $ | — |
| | $ | — |
| | $ | 554 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 479 |
| | $ | 181 |
| | $ | — |
| | $ | — |
| | $ | 660 |
|
| |
(a) | Energy-related derivatives excludes $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives excludes cash collateral of $193 million. |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
As of December 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using | | |
As of December 31, 2016: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 338 |
| | $ | 239 |
| | $ | — |
| | $ | — |
| | $ | 577 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 345 |
| | $ | 224 |
| | $ | — |
| | $ | — |
| | $ | 569 |
|
| |
(a) | Energy-related derivatives excludes $4 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
(b) | Energy-related derivatives excludes cash collateral of $62 million. |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded financial products for natural gas, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard OTC products that are valued using observable market data and assumptions commonly used by market participants. See Note 10 for additional information on how these derivatives are used.
Debt
The Company's long-term debt is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. The Company amortizes the fair value adjustments over the lives of the respective bonds. The following table presents the carrying amount and fair value of the Company's long-term debt as of December 31:
|
| | | | | | | |
| Carrying Amount | | Fair Value |
| (in millions) |
Long-term debt, including securities due within one year: | | | |
2017 | $ | 6,048 |
| | $ | 6,471 |
|
2016 | $ | 5,281 |
| | $ | 5,491 |
|
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Company.
10. DERIVATIVES
The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. Wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For other businesses, the Company's policy is that derivatives are to be used primarily for hedging purposes. In both cases, the Company mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.
Energy-Related Derivatives
The Company enters into energy-related derivatives to hedge exposures to natural gas price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, gas distribution operations has limited exposure to market volatility in prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the natural gas
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
distribution utilities' respective state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. However, the Company retains exposure to price changes that can, in a volatile energy market, be extremely material and can adversely affect the Company.
The Company also enters into weather derivative contracts as economic hedges of adjusted operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.
Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through the respective cost recovery clauses.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in other OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income in the period of change.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 300 million mmBtu for the Company, together with the longest hedge date of 2020 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2026 for derivatives not designated as hedges.
For cash flow hedges, the estimated pre-tax losses that will be reclassified from accumulated OCI to earnings for the 12-month period ending December 31, 2018 are $4 million.
Interest Rate Derivatives
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
In 2015, the Company executed $800 million in notional value of 10-year and 30-year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility designated as cash flow hedges of issuances of long-term debt in the fourth quarter 2015 and during 2016. The Company settled $200 million of these interest rate swaps in 2015 for an immaterial loss, $400 million in May 2016 at a loss of $26 million, and the remaining $200 million in September 2016 at a loss of $35 million. Due to the application of acquisition accounting, only $5 million of the pre-tax loss incurred and deferred in the successor period is being amortized to interest expense through 2046.
Derivative Financial Statement Presentation and Amounts
The derivative contracts of the Company are subject to master netting arrangements or similar agreements and are reported net in the financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
At December 31, 2017 and 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | |
| 2017 | 2016 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | 5 |
| $ | 8 |
| $ | 24 |
| $ | 3 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 5 |
| $ | 8 |
| $ | 25 |
| $ | 3 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | — |
| $ | 3 |
| $ | 4 |
| $ | 3 |
|
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | 379 |
| $ | 434 |
| $ | 486 |
| $ | 482 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 170 |
| 215 |
| 66 |
| 81 |
|
Total derivatives not designated as hedging instruments | $ | 549 |
| $ | 649 |
| $ | 552 |
| $ | 563 |
|
Gross amounts recognized | $ | 554 |
| $ | 660 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(a) | $ | (390 | ) | $ | (583 | ) | $ | (435 | ) | $ | (497 | ) |
Net amounts recognized in the Balance Sheets (b) | $ | 164 |
| $ | 77 |
| $ | 146 |
| $ | 72 |
|
| |
(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $193 million and $62 million as of December 31, 2017 and 2016, respectively. |
| |
(b) | Net amount of derivative instruments outstanding excludes premiums and intrinsic value associated with weather derivatives of $11 million as of December 31, 2017. |
At December 31, 2017 and 2016, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivatives designated as regulatory hedging instruments and deferred were as follows:
|
| | | | | | | | | | | | | | |
| | Unrealized Losses | | Unrealized Gains |
Derivative Category | Balance Sheet Location | 2017 | 2016 | Balance Sheet Location | 2017 | 2016 |
| | (in millions) | | (in millions) |
Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (4 | ) | $ | (1 | ) | Other regulatory liabilities, current | $ | 7 |
| $ | 17 |
|
| Other regulatory assets, deferred | — |
| — |
| Other regulatory liabilities, deferred | — |
| 1 |
|
Total energy-related derivative gains (losses)(*) | $ | (4 | ) | $ | (1 | ) | | $ | 7 |
| $ | 18 |
|
(*) Fair value gains and losses included in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million as of December 31, 2017 and $8 million as of December 31, 2016.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
For all periods presented, the pre-tax effect of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were as follows:
|
| | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Successor | | Successor |
Derivatives in Cash Flow Hedging Relationships | 2017 | Statements of Income Location | 2017 |
| (in millions) | | (in millions) |
Energy-related derivatives | $ | (9 | ) | Cost of natural gas | $ | (2 | ) |
|
| | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Successor | | | Predecessor | | | Successor | | | Predecessor |
Derivatives in Cash Flow Hedging Relationships | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | Statements of Income Location | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 |
| (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
Energy-related derivatives | $ | 2 |
| | | $ | — |
| | Cost of natural gas | $ | (1 | ) | | | $ | (1 | ) |
Interest rate derivatives | (5 | ) | | | (64 | ) | | Interest expense, net of amounts capitalized | — |
| | | — |
|
Total derivatives in cash flow hedging relationships | $ | (3 | ) | | | $ | (64 | ) | | | $ | (1 | ) | | | $ | (1 | ) |
|
| | | | | | | |
| Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| Predecessor | | Predecessor |
Derivatives in Cash Flow Hedging Relationships | 2015 | Statements of Income Location | 2015 |
| (in millions) | | (in millions) |
Energy-related derivatives | $ | 3 |
| Cost of natural gas | $ | (10 | ) |
| | Other operations and maintenance | (1 | ) |
Interest rate derivatives | — |
| Interest expense, net of amounts capitalized | 2 |
|
Total derivatives in cash flow hedging relationships | $ | 3 |
| | $ | (9 | ) |
There was no material ineffectiveness recorded in earnings for any period presented.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
For all periods presented, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows: |
| | | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Successor | | | Predecessor |
Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Year Ended December 31, 2017 | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | Year Ended December 31, 2015 |
| | (in millions) | | | (in millions) |
Energy-related derivatives | Natural gas revenues(*) | $ | (80 | ) | $ | 33 |
| | | $ | (1 | ) | $ | 56 |
|
| Cost of natural gas | (2 | ) | 3 |
| | | (62 | ) | (6 | ) |
Total derivatives in non-designated hedging relationships | $ | (82 | ) | $ | 36 |
| | | $ | (63 | ) | $ | 50 |
|
| |
(*) | Excludes the impact of weather derivatives recorded in natural gas revenues of $23 million for the successor year ended December 31, 2017, $6 million for the successor period of July 1, 2016 through December 31, 2016, $3 million for the predecessor period of January 1, 2016 through June 30, 2016, and $12 million for the predecessor year ended December 31, 2015. |
Contingent Features
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.
At December 31, 2017, the fair value of derivative liabilities with contingent features was $3 million and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was $2 million.
Generally, collateral may be provided by a guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Prior to entering into a physical transaction, the Company assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. The Company may require counterparties to pledge additional collateral when deemed necessary. Credit evaluations are conducted and appropriate internal approvals are obtained for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, the Company requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company's credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
11. MERGER, ACQUISITION, AND DISPOSITIONS
Merger with Southern Company
On July 1, 2016, the Company completed the Merger with Southern Company. A wholly-owned, direct subsidiary of Southern Company merged with and into Southern Company Gas, with the Company surviving as a wholly-owned, direct subsidiary of Southern Company.
At the effective time of the Merger, each share of Southern Company Gas common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the Merger, all of the outstanding restricted stock units, restricted stock awards, non-employee director stock awards, stock options, and performance share units were either redeemed or converted into Southern Company's restricted stock units. See Note 8 for additional information.
The application of the acquisition method of accounting was pushed down to the Company. The excess of the purchase price over the fair values of the Company's assets and liabilities was recorded as goodwill, which represents a different basis of accounting from the historical basis prior to the Merger. The following table presents the final purchase price allocation:
|
| | | | | | | | | | | | |
| Successor | | | Predecessor | | |
| New Basis | | | Old Basis | | Change in Basis |
| (in millions) | | | (in millions) |
Current assets | $ | 1,557 |
| | | $ | 1,474 |
| | $ | 83 |
|
Property, plant, and equipment | 10,108 |
| | | 10,148 |
| | (40 | ) |
Goodwill | 5,967 |
| | | 1,813 |
| | 4,154 |
|
Other intangible assets | 400 |
| | | 101 |
| | 299 |
|
Regulatory assets | 1,118 |
| | | 679 |
| | 439 |
|
Other assets | 229 |
| | | 273 |
| | (44 | ) |
Current liabilities | (2,201 | ) | | | (2,205 | ) | | 4 |
|
Other liabilities | (4,742 | ) | | | (4,600 | ) | | (142 | ) |
Long-term debt | (4,261 | ) | | | (3,709 | ) | | (552 | ) |
Contingently redeemable noncontrolling interest | (174 | ) | | | (41 | ) | | (133 | ) |
Total purchase price/equity | $ | 8,001 |
| | | $ | 3,933 |
| | $ | 4,068 |
|
Measurement period adjustments were recorded to the purchase price allocation during the fourth quarter 2016, which resulted in a net $30 million increase in goodwill to establish intangible liabilities for transportation contracts at wholesale services, partially offset by adjustments to deferred tax balances.
In determining the fair value of assets and liabilities subject to rate regulation that allows recovery of costs and/or a fair return on investments, historical cost was deemed to be a reasonable proxy for fair value, as it is included in rate base or otherwise specified in regulatory recovery mechanisms. Property, plant, and equipment subject to rate regulation was reflected based on the historical gross amount of assets in service and accumulated depreciation, as they are included in rate base. For certain assets and liabilities subject to rate regulation (such as debt instruments and employee benefit obligations), the fair value adjustment was applied to historical cost with a corresponding offset to regulatory asset or liability based on the assessment of probable future recovery in rates.
For unregulated assets and liabilities, fair value adjustments were applied to historical cost of natural gas for sale, property, plant, and equipment, debt instruments, and noncontrolling interest. The valuation of other intangible assets included customer relationships, trade names, and favorable/unfavorable contracts. The valuation of these assets and liabilities applied either the market approach or income approach. The market approach was utilized when prices and other relevant market information were available. The income approach, which is based on discounted cash flows, was primarily based on significant unobservable inputs (Level 3). Key estimates and inputs included forecasted profitability and cash flows, customer retention rates, royalty rates, and discount rates.
The estimated fair value of deferred income taxes was determined by applying the appropriate enacted statutory tax rate to the temporary differences that arose on the differences between the financial reporting value and tax basis of the assets acquired and liabilities assumed.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
The excess of the purchase price over the estimated fair value of assets and liabilities of $6 billion was recognized as goodwill, which is primarily attributable to positioning Southern Company to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. The Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.
The receipt of required regulatory approvals was conditioned upon certain terms and commitments. In connection with these regulatory approvals, certain regulatory agencies prohibited the Company from recovering goodwill and Merger-related expenses, required the Company to maintain a minimum number of employees for a set period of time to ensure that certain pipeline safety standards and the competence level of the employee workforce is not degraded, and/or required the Company to maintain its pre-Merger level of support for various social and charitable programs. The most notable terms and commitments with potential financial impacts included:
rate credits of $18 million to be paid to customers in New Jersey and Maryland;
sharing of Merger savings with customers in Georgia starting in 2020;
phasing-out the use of the Nicor name or logo by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois;
reaffirming that Elizabethtown Gas would file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case; and
requiring Elkton Gas to file a base rate case within two years of closing the Merger.
There is no restriction on the Company's other utilities' ability to file future rate cases. The rate credits to customers in New Jersey and Maryland were paid during the third and fourth quarters of 2016, respectively. The use of the Nicor name and logo was phased out, effective November 1, 2017, by certain of the Company's gas marketing services subsidiaries in conducting non-utility business in Illinois. Elizabethtown Gas filed a base rate case with the New Jersey BPU on September 1, 2016. See Note 3 under "Base Rate Cases" for additional information. Upon completion of the Merger, the Company amended and restated its Bylaws and Articles of Incorporation, under which it now has the authority to issue no more than 110 million shares of stock consisting of (i) 100 million shares of common stock and (ii) 10 million shares of preferred stock, both categories of which have a par value of $0.01 per share. The amended and restated Articles of Incorporation do not allow any treasury shares to be held.
Investment in SNG
In September 2016, the Company, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG pursuant to a definitive agreement between Southern Company and Kinder Morgan, Inc. in July 2016, to which Southern Company assigned all rights and obligations to the Company in August 2016. SNG owns a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The purchase price of $1.4 billion was financed by a $1.05 billion equity contribution from Southern Company and $360 million of cash paid by the Company, which was financed by a promissory note from Southern Company repaid with a portion of the proceeds from senior notes issued in September 2016. The purchase price of the 50% equity interest exceeded the underlying ownership interest in the net assets of SNG by approximately $700 million. This basis difference is attributable to goodwill and deferred tax assets. While the deferred tax assets will be amortized through deferred tax expense, the goodwill will not be amortized and is not required to be tested for impairment on an annual basis. The Company's investment in SNG decreased by $104 million related to the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings.
On March 31, 2017, the Company made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 4 under "Equity Method Investments" for additional information on this investment.
Proposed Sale of Elizabethtown Gas and Elkton Gas
On October 15, 2017, the Company's subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of each asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC. The Company and South Jersey Industries, Inc. made joint filings on December 22, 2017 and January 16, 2018 with the New Jersey BPU and the Maryland PSC, respectively, requesting regulatory approval. The asset sales are expected to be completed by the end of the third quarter 2018.
The ultimate outcome of these matters cannot be determined at this time.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
12. SEGMENT AND RELATED INFORMATION
The Company manages its business through four reportable segments - gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other. In conjunction with the Merger, the Company changed the names of certain reportable segments to better align with its new parent company.
Gas distribution operations is the largest component of the Company's business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. Wholesale gas services provides natural gas asset management and/or related logistics services for each of the Company's utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Since the acquisition of the Company's 50% interest in SNG, gas midstream operations primarily consists of the Company's gas pipeline investments, with storage and fuel operations also aggregated into this segment. The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.
After the Merger, the Company changed the segment performance measure to net income, which is utilized by its parent company. In order to properly assess net income by segment, the Company executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor periods, the Company is unable to provide the comparable net income for those periods.
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
Financial data for business segments for the successor year ended December 31, 2017, the successor period of July 1, 2016 through December 31, 2016, and the predecessor periods of January 1, 2016 through June 30, 2016 and the year ended December 31, 2015 were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | | Gas Marketing Services | | Wholesale Gas Services(a) | | Gas Midstream Operations | | Total | | All Other | | Eliminations | | Consolidated |
| (in millions) |
Successor – Year ended December 31, 2017 | | | | | | | | | | |
Operating revenues | $ | 3,207 |
| | $ | 860 |
| | $ | 6 |
| | $ | 71 |
| | $ | 4,144 |
| | $ | 10 |
| | $ | (234 | ) | | $ | 3,920 |
|
Depreciation and amortization | 391 |
| | 62 |
| | 2 |
| | 18 |
| | 473 |
| | 28 |
| | — |
| | 501 |
|
Operating income (loss) | 650 |
| | 113 |
| | (51 | ) | | (10 | ) | | 702 |
| | (37 | ) | | — |
| | 665 |
|
Earnings from equity method investments | — |
| | — |
| | — |
| | 103 |
| | 103 |
| | 3 |
| | — |
| | 106 |
|
Interest expense | (153 | ) | | (5 | ) | | (7 | ) | | (33 | ) | | (198 | ) | | (2 | ) | | — |
| | (200 | ) |
Income taxes(b) | 178 |
| | 24 |
| | — |
| | 61 |
| | 263 |
| | 104 |
| | — |
| | 367 |
|
Segment net income (loss)(b) | 353 |
| | 84 |
| | (57 | ) | | 3 |
| | 383 |
| | (140 | ) | | — |
| | 243 |
|
Gross property additions | 1,330 |
| | 9 |
| | 1 |
| | 134 |
| | 1,474 |
| | 34 |
| | — |
| | 1,508 |
|
Successor – Total assets at December 31, 2017 | 19,358 |
| | 2,147 |
| | 1,096 |
| | 2,241 |
| | 24,842 |
| | 12,184 |
| | (14,039 | ) | | 22,987 |
|
Successor – July 1, 2016 through December 31, 2016 | | | | | | | | | | |
Operating revenues | $ | 1,342 |
| | $ | 354 |
| | $ | 24 |
| | $ | 31 |
| | $ | 1,751 |
| | $ | 3 |
| | $ | (102 | ) | | $ | 1,652 |
|
Depreciation and amortization | 185 |
| | 35 |
| | 1 |
| | 9 |
| | 230 |
| | 8 |
| | — |
| | 238 |
|
Operating income (loss) | 222 |
| | 27 |
| | (2 | ) | | (7 | ) | | 240 |
| | (43 | ) | | — |
| | 197 |
|
Earnings from equity method investments | — |
| | — |
| | — |
| | 58 |
| | 58 |
| | 2 |
| | — |
| | 60 |
|
Interest expense | (105 | ) | | (1 | ) | | (3 | ) | | (16 | ) | | (125 | ) | | 44 |
| | — |
| | (81 | ) |
Income taxes | 51 |
| | 7 |
| | (3 | ) | | 16 |
| | 71 |
| | 5 |
| | — |
| | 76 |
|
Segment net income (loss) | 77 |
| | 19 |
| | — |
| | 20 |
| | 116 |
| | (2 | ) | | — |
| | 114 |
|
Gross property additions | 561 |
| | 5 |
| | 1 |
| | 54 |
| | 621 |
| | 11 |
| | — |
| | 632 |
|
Successor – Total assets at December 31, 2016 | 19,453 |
| | 2,084 |
| | 1,127 |
| | 2,211 |
| | 24,875 |
| | 11,145 |
| | (14,167 | ) | | 21,853 |
|
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | | Gas Marketing Services | | Wholesale Gas Services(a) | | Gas Midstream Operations | | Total | | All Other | | Eliminations | | Consolidated |
| (in millions) |
Predecessor – January 1, 2016 through June 30, 2016 | | | | | | | | | | |
Operating revenues | $ | 1,575 |
| | $ | 435 |
| | $ | (32 | ) | | $ | 25 |
| | $ | 2,003 |
| | $ | 4 |
| | $ | (102 | ) | | $ | 1,905 |
|
Depreciation and amortization | 178 |
| | 11 |
| | 1 |
| | 9 |
| | 199 |
| | 7 |
| | — |
| | 206 |
|
Operating income (loss) | 351 |
| | 109 |
| | (69 | ) | | (9 | ) | | 382 |
| | (61 | ) | | — |
| | 321 |
|
EBIT | 353 |
| | 109 |
| | (68 | ) | | (6 | ) | | 388 |
| | (60 | ) | | — |
| | 328 |
|
Gross property additions | 484 |
| | 4 |
| | 1 |
| | 43 |
| | 532 |
| | 16 |
| | — |
| | 548 |
|
Predecessor – Year Ended December 31, 2015 | | | |
| | | | | |
|
Operating revenues | $ | 3,049 |
| | $ | 835 |
| | $ | 202 |
| | $ | 55 |
| | $ | 4,141 |
| | $ | 11 |
| | $ | (211 | ) | | $ | 3,941 |
|
Depreciation and amortization | 336 |
| | 25 |
| | 1 |
| | 18 |
| | 380 |
| | 17 |
| | — |
| | 397 |
|
Operating income (loss) | 571 |
| | 152 |
| | 112 |
| | (26 | ) | | 809 |
| | (63 | ) | | — |
| | 746 |
|
EBIT | 581 |
| | 152 |
| | 110 |
| | (23 | ) | | 820 |
| | (59 | ) | | — |
| | 761 |
|
Gross property additions | 957 |
| | 7 |
| | 2 |
| | 27 |
| | 993 |
| | 34 |
| | — |
| | 1,027 |
|
Predecessor – Total assets at December 31, 2015 | 12,519 |
| | 686 |
| | 935 |
| | 692 |
| | 14,832 |
| | 9,662 |
| | (9,740 | ) | | 14,754 |
|
(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
| | | | | | | | | | | | | | | | | | | |
| Third Party Gross Revenues | | Intercompany Revenues | | Total Gross Revenues | | Less Gross Gas Costs | | Operating Revenues |
| (in millions) |
Successor – Year Ended December 31, 2017 | $ | 6,152 |
| | $ | 481 |
| | $ | 6,633 |
| | $ | 6,627 |
| | $ | 6 |
|
Successor – July 1, 2016 through December 31, 2016 | 5,807 |
| | 333 |
| | 6,140 |
| | 6,116 |
| | 24 |
|
| (in millions) |
Predecessor – January 1, 2016 through June 30, 2016 | $ | 2,500 |
| | $ | 143 |
| | $ | 2,643 |
| | $ | 2,675 |
| | $ | (32 | ) |
Predecessor – Year Ended December 31, 2015 | 6,286 |
| | 408 |
| | 6,694 |
| | 6,492 |
| | 202 |
|
| |
(b) | Includes the impact of the Tax Reform Legislation and new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. |
NOTES (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
13. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 and for the predecessor period of January 1, 2016 through June 30, 2016 are as follows:
|
| | | | | | | | | | | | | | | |
Quarter Ended | Operating Revenues | | Operating Income (Loss) | | EBIT | | Net Income (Loss) Attributable to Southern Company Gas |
| (in millions) |
Successor - 2017 | | | | | | | |
March 2017 | $ | 1,560 |
| | $ | 391 |
| | $ | 435 |
| | $ | 239 |
|
June 2017 | 716 |
| | 96 |
| | 128 |
| | 49 |
|
September 2017(a) | 565 |
| | 68 |
| | 118 |
| | 15 |
|
December 2017(a)(b) | 1,079 |
| | 110 |
| | 129 |
| | (60 | ) |
Predecessor - January 1, 2016 through June 30, 2016 | (in millions) |
March 2016 | $ | 1,334 |
| | $ | 348 |
| | $ | 351 |
| | $ | 182 |
|
June 2016 | 571 |
| | (27 | ) | | (23 | ) | | (51 | ) |
Successor - July 1, 2016 through December 31, 2016 | (in millions) |
September 2016 | $ | 543 |
| | $ | 12 |
| | $ | 50 |
| | $ | 4 |
|
December 2016 | 1,109 |
| | 185 |
| | 221 |
| | 110 |
|
| |
(a) | Net income (loss) attributable to Southern Company Gas includes the impact of new income tax apportionment factors in several states resulting from the Company's inclusion in the consolidated Southern Company state tax filings. |
| |
(b) | Net loss attributable to Southern Company Gas includes the impact of the Tax Reform Legislation. |
The Company's business is influenced by seasonal weather conditions.
See Note 11 under "Merger with Southern Company" for information on the Merger.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2013-2017
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | 2015 | | 2014 | | 2013 |
Operating Revenues (in millions) | $ | 3,920 |
| | $ | 1,652 |
| | | $ | 1,905 |
| | $ | 3,941 |
| | $ | 5,385 |
| | $ | 4,209 |
|
Net Income Attributable to Southern Company Gas (in millions) | $ | 243 |
| | $ | 114 |
| | | $ | 131 |
| | $ | 353 |
| | $ | 482 |
| | $ | 295 |
|
Cash Dividends on Common Stock (in millions) | $ | 443 |
| | $ | 126 |
| | | $ | 128 |
| | $ | 244 |
| | $ | 233 |
| | $ | 222 |
|
Return on Average Common Equity (percent) | 2.68 |
| | 1.74 |
| | | 3.31 |
| | 9.05 |
| | 12.96 |
| | 8.42 |
|
Total Assets (in millions) | $ | 22,987 |
| | $ | 21,853 |
| | | $ | 14,488 |
| | $ | 14,754 |
| | $ | 14,888 |
| | $ | 14,528 |
|
Gross Property Additions (in millions) | $ | 1,525 |
| | $ | 632 |
| | | $ | 548 |
| | $ | 1,027 |
| | $ | 769 |
| | $ | 731 |
|
Capitalization (in millions): | | | | | | | | | | | | |
Common stock equity | $ | 9,022 |
| | $ | 9,109 |
| | | $ | 3,933 |
| | $ | 3,975 |
| | $ | 3,828 |
| | $ | 3,613 |
|
Long-term debt | 5,891 |
| | 5,259 |
| | | 3,709 |
| | 3,275 |
| | 3,581 |
| | 3,791 |
|
Total (excluding amounts due within one year) | $ | 14,913 |
| | $ | 14,368 |
| | | $ | 7,642 |
| | $ | 7,250 |
| | $ | 7,409 |
| | $ | 7,404 |
|
Capitalization Ratios (percent): | | | | | | | | | | | | |
Common stock equity | 60.5 |
| | 63.4 |
| | | 51.5 |
| | 54.8 |
| | 51.7 |
| | 48.8 |
|
Long-term debt | 39.5 |
| | 36.6 |
| | | 48.5 |
| | 45.2 |
| | 48.3 |
| | 51.2 |
|
Total (excluding amounts due within one year) | 100.0 |
| | 100.0 |
| | | 100.0 |
| | 100.0 |
| | 100.0 |
| | 100.0 |
|
Service Contracts (period-end) | 1,184,257 |
| | 1,198,263 |
| | | 1,197,096 |
| | 1,205,476 |
| | 1,162,065 |
| | 1,176,908 |
|
Customers (period-end) | | | | | | | | | | | | |
Gas distribution operations | 4,623,249 |
| | 4,586,477 |
| | | 4,544,489 |
| | 4,557,729 |
| | 4,529,114 |
| | 4,504,067 |
|
Gas marketing services | 773,984 |
| | 655,999 |
| | | 630,475 |
| | 654,475 |
| | 633,460 |
| | 632,337 |
|
Total (period-end) | 5,397,233 |
| | 5,242,476 |
| | | 5,174,964 |
| | 5,212,204 |
| | 5,162,574 |
| | 5,136,404 |
|
Employees (period-end) | 5,318 |
| | 5,292 |
| | | 5,284 |
| | 5,203 |
| | 5,165 |
| | 6,094 |
|
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2013-2017 (continued)
Southern Company Gas and Subsidiary Companies 2017 Annual Report
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2017 | | July 1, 2016 through December 31, 2016 | | | January 1, 2016 through June 30, 2016 | | 2015 | | 2014 | | 2013 |
Operating Revenues (in millions) | | | | | | | | | | | | |
Residential | $ | 2,100 |
| | $ | 899 |
| | | $ | 1,101 |
| | $ | 2,129 |
| | $ | 2,877 |
| | $ | 2,422 |
|
Commercial | 641 |
| | 260 |
| | | 310 |
| | 617 |
| | 861 |
| | 696 |
|
Transportation | 811 |
| | 269 |
| | | 290 |
| | 526 |
| | 458 |
| | 487 |
|
Industrial | 159 |
| | 74 |
| | | 72 |
| | 203 |
| | 242 |
| | 180 |
|
Other | 209 |
| | 150 |
| | | 132 |
| | 466 |
| | 947 |
| | 424 |
|
Total | $ | 3,920 |
| | $ | 1,652 |
| | | $ | 1,905 |
| | $ | 3,941 |
| | $ | 5,385 |
| | $ | 4,209 |
|
Heating Degree Days: | | | | | | | | | | | | |
Illinois | 5,246 |
| | 1,903 |
| | | 3,340 |
| | 5,433 |
| | 6,556 |
| | 6,305 |
|
Georgia | 1,970 |
| | 727 |
| | | 1,448 |
| | 2,204 |
| | 2,882 |
| | 2,689 |
|
Gas Sales Volumes (mmBtu in millions): | | | | | | | | | | | | |
Gas distributions operations | | | | | | | | | | | | |
Firm | 667 |
| | 274 |
| | | 396 |
| | 695 |
| | 766 |
| | 720 |
|
Interruptible | 95 |
| | 47 |
| | | 49 |
| | 99 |
| | 106 |
| | 111 |
|
Total | 762 |
| | 321 |
| | | 445 |
| | 794 |
| | 872 |
| | 831 |
|
Gas marketing services | | | | | | | | | | | | |
Firm: | | | | | | | | | | | | |
Georgia | 23 |
| | 13 |
| | | 21 |
| | 35 |
| | 41 |
| | 38 |
|
Illinois | 8 |
| | 4 |
| | | 8 |
| | 13 |
| | 17 |
| | 9 |
|
Other emerging markets | 15 |
| | 5 |
| | | 7 |
| | 11 |
| | 10 |
| | 8 |
|
Interruptible (large commercial and industrial) | 11 |
| | 6 |
| | | 8 |
| | 14 |
| | 17 |
| | 18 |
|
Total | 57 |
| | 28 |
| | | 44 |
| | 73 |
| | 85 |
| | 73 |
|
Market share in Georgia (percent) | 29.2 |
| | 29.4 |
| | | 29.3 |
| | 29.7 |
| | 30.6 |
| | 31.4 |
|
Wholesale gas services | | | | | | | | | | | | |
Daily physical sales (mmBtu in millions/day) | 6.4 |
| | 7.2 |
| | | 7.6 |
| | 6.8 |
| | 6.3 |
| | 5.7 |
|
PART III
Items 10 11, 12 (other than the information under "Code of Ethics" below in Item 10)below), 11, 12, 13, and 14 for Southern Company are incorporated by reference to Southern Company's Definitive Proxy Statement relating to the 20162018 Annual Meeting of Stockholders. Specifically, reference is made to "Corporate Governance"Governance at Southern Company" and "Section 16(a) Beneficial Ownership Reporting Compliance" for Item 10, "Compensation Discussion and Analysis," "Executive Compensation" "Director Compensation," "Director Deferred Compensation Plan, Tables," and "Director Compensation Table"Compensation" for Item 11, "Stock Ownership Table"Information," "Executive Compensation Tables," and "Executive Compensation""Equity Compensation Plan Information" for Item 12, "Certain Relationships and Related Transactions" and "Director Independence""Southern Company Board" for Item 13, and "Principal Independent Registered Public Accounting Firm Fees" for Item 14.
Items 10 11, 12 (other than the information under "Code of Ethics" below in Item 10)below), 11, 12, 13, and 14 for Alabama Power, Georgia Power and Mississippi Power are incorporated by reference to the Definitive Information Statements of Alabama Power Georgia Power, and Mississippi Power relating to each of their respective 20162018 Annual Meetings of Shareholders. Specifically, reference is made to "Nominees for Election as Directors," "Corporate Governance," and "Section 16(a) Beneficial Ownership Reporting Compliance" for Item 10, "Executive Compensation," "Compensation Committee Interlocks and Insider Participation," "Director Compensation," "Director Deferred Compensation Plan," and "Director Compensation Table" for Item 11, "Stock Ownership Table" and "Executive Compensation" for Item 12, "Certain Relationships and Related Transactions" and "Director Independence" for Item 13, and "Principal Independent Registered Public Accounting Firm Fees" for Item 14.
Items 10, 11, 12, 13, and 14 for Gulf Power are contained herein.
Items 10, 11, 12, and 13 for each of Georgia Power, Gulf Power, Southern Power, and Southern Company Gas are omitted pursuant to General Instruction I(2)(c) of Form 10-K. Item 14 for each of Georgia Power, Gulf Power, Southern Power, and Southern Company Gas is contained herein.
PART III
|
| |
ItemITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Identification of directors of Gulf Power (1)
|
| |
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer
Age 46
Served as Director since 2012
| Julian B. MacQueen (2)
Age 65
Served as Director since 2013
|
Allan G. Bense (2)
Age 64
Served as Director since 2010
| J. Mort O'Sullivan, III(2)
Age 64
Served as Director since 2010
|
Deborah H. Calder (2)
Age 55
Served as Director since 2010
| Michael T. Rehwinkel (2)
Age 59
Served as Director since 2013
|
William C. Cramer, Jr. (2)
Age 63
Served as Director since 2002
| Winston E. Scott(2)
Age 65
Served as Director since 2003
|
| |
(1) | Ages listed are as of December 31, 2015. |
| |
(2) | No position other than director. |
Each of the above is currently a director of Gulf Power, serving a term running from the last annual meeting of Gulf Power's shareholders (June 30, 2015) for one year until the next annual meeting or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as a director, other than any arrangements or understandings with directors or officers of Gulf Power acting solely in their capacities as such.
Identification of executive officers of Gulf Power (1)
|
| |
S. W. Connally, Jr.
Chairman, President, and Chief Executive Officer
Age 46
Served as Executive Officer since 2012
| Michael L. Burroughs
Vice President — Senior Production Officer
Age 55
Served as Executive Officer since 2010
|
Jim R. Fletcher
Vice President — External Affairs and Corporate Services
Age 49
Served as Executive Officer since 2014
| Wendell E. Smith
Vice President — Power Delivery
Age 50
Served as Executive Officer since 2014
|
Xia Liu
Vice President and Chief Financial Officer
Age 45
Served as Executive Officer since 2015
| Bentina C. Terry
Vice President — Customer Service and Sales
Age 45
Served as Executive Officer since 2007
|
| |
(1) | Ages listed are as of December 31, 2015. |
Each of the above is currently an executive officer of Gulf Power, serving a term until the next annual organizational meeting of the Board of Directors or until a successor is elected and qualified.
There are no arrangements or understandings between any of the individuals listed above and any other person pursuant to which he or she was or is to be selected as an officer, other than any arrangements or understandings with directors or officers of Gulf Power acting solely in their capacities as such.
Identification of certain significant employees.None.
Family relationships.None.
Business experience.Unless noted otherwise, each director has served in his or her present position for at least the past five years.
DIRECTORS
Gulf Power's Board of Directors possesses collective knowledge and experience in accounting, finance, leadership, business operations, risk management, corporate governance, and Gulf Power's industry.
S. W. Connally, Jr. - Mr. Connally was elected Chairman in July 2015 and has served as President, Chief Executive Officer, and Director since July 2012. Mr. Connally has also served as Chairman of Gulf Power's Board of Directors since July 2012. Mr. Connally previously served as Senior Vice President and Chief Production Officer of Georgia Power from August 2010 through June 2012.
Allan G. Bense - Panama City businessman and former Speaker of the Florida House of Representatives. Mr. Bense is a partner in several companies involved in road building, mechanical contracting, insurance, general contracting, golf courses, and farming. Mr. Bense served as Vice Chair of Enterprise Florida, the economic development agency for the state, from January 2009 to January 2011. Mr. Bense also has been a member of the board of directors of Capital City Bank Group, Inc. since 2013.
Deborah H. Calder - Executive Vice President for Navy Federal Credit Union since 2014. From 2008 to 2014, she served as Senior Vice President. Ms. Calder directs the day-to-day operations of more than 4,500 employees and the ongoing construction of Navy Federal Credit Union's campus in the Pensacola area. Ms. Calder has been with Navy Federal Credit Union for over 24 years, serving in previous positions as Vice President of Consumer and Credit Card Lending, Vice President of Collections, Vice President of Call Center Operations, and Assistant Vice President of Credit Cards.
William C. Cramer, Jr. - President and Owner of automobile dealerships in Florida and Alabama. Mr. Cramer has been an authorized Chevrolet dealer for over 26 years. In 2009, Mr. Cramer became an authorized dealer of Cadillac, Buick, and GMC vehicles.
Julian B. MacQueen - Founder and Chief Executive Officer of Innisfree Hotels, Inc. He is currently a member of the American Hotel & Lodging Association and a director of the Beach Community Bank.
J. Mort O'Sullivan, III - Managing Member of the Gulf Coast division of Warren Averett, LLC, a CPA and Advisory firm. Mr. O'Sullivan currently focuses on consulting and management advisory services to clients, while continuing to offer his expertise in litigation support, business valuations, wealth management, and mergers and acquisitions. He is a registered investment advisor.
Michael T. Rehwinkel - Mr. Rehwinkel previously served as Executive Chairman of EVRAZ North America, a steel manufacturer, from July 2013 to December 2015 and as Chief Executive Officer and President from February 2010 to July
2013. Mr. Rehwinkel also served as Chairman of the American Iron and Steel Institute in 2012 and 2013. Mr. Rehwinkel has more than 30 years of industrial business and leadership experience.
Winston E. Scott - Senior Vice President for External Relations and Economic Development, Florida Institute of Technology since March 2012. He previously served as Dean, College of Aeronautics, Florida Institute of Technology, Melbourne, Florida from August 2008 through March 2012. Mr. Scott is also a member of the board of directors of Environmental Tectonics Corporation.
EXECUTIVE OFFICERS
Michael L. Burroughs - Vice President and Senior Production Officer since August 2010. He previously served as Manager of Georgia Power's Plant Yates from September 2007 to July 2010.
Jim R. Fletcher - Vice President of External Affairs and Corporate Services since March 2014. He previously served as Vice President of Governmental and Regulatory Affairs for Georgia Power from January 2011 to February 2014 and Regulatory Affairs Manager for Georgia Power from March 2006 to January 2011.
Xia Liu - Vice President and Chief Financial Officer since June 2015. She previously served as Treasurer of Southern Company and Senior Vice President of Finance and Treasurer of SCS from March 2014 to June 2015 and Assistant Treasurer of Southern Company and Vice President of Finance and Assistant Treasurer of SCS from July 2010 to March 2014.
Wendell E. Smith - Vice President of Power Delivery since March 2014. He previously served as the General Manager of Distribution Engineering, Construction and Maintenance and Distribution Operations Systems for Georgia Power from January 2012 to February 2014, Transmission Construction Manager for Georgia Power from February 2011 to December 2011, and Distribution Manager for Georgia Power from March 2005 to February 2011.
Bentina C. Terry - Vice President of Customer Service and Sales since March 2014. She previously served as Vice President of External Affairs and Corporate Services from March 2007 to March 2014.
Involvement in certain legal proceedings. None.
Promoters and Control Persons. None.
Section 16(a) Beneficial Ownership Reporting Compliance. No late filings to report.
Code of Ethics
The registrants collectively have adopted a code of business conduct and ethics (Code of Ethics) that applies to each director, officer, and employee of the registrants and their subsidiaries. The Code of Ethics can be found on Southern Company's website located at www.southerncompany.com. The Code of Ethics is also available free of charge in print to any shareholder by requesting a copy from Melissa K. Caen,Myra C. Bierria, Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308. Any amendment to or waiver from the Code of Ethics that applies to executive officers and directors will be posted on the website.
Corporate Governance
Southern Company has adopted corporate governance guidelines and committee charters. The corporate governance guidelines and the charters of Southern Company's Audit Committee, Compensation and Management Succession Committee, Finance Committee, Governance Committee, and Nuclear/Operations Committee can be found on Southern Company's website located at www.southerncompany.com. The corporate governance guidelines and charters are also available free of charge in print to any shareholder by requesting a copy from Melissa K. Caen, Corporate Secretary, Southern Company, 30 Ivan Allen Jr. Boulevard NW, Atlanta, Georgia 30308.
Southern Company owns all of Gulf Power’s outstanding common stock and Gulf Power has listed only debt securities on the NYSE. Accordingly, under the rules of the NYSE, Gulf Power is exempt from most of the NYSE's listing standards relating to corporate governance. In addition, under the rules of the SEC, Gulf Power is exempt from the audit committee requirements of Section 301 of the Sarbanes-Oxley Act of 2002 and, therefore, is not required to have an audit committee or an audit committee report on whether it has an audit committee financial expert.
| |
Item 11. | EXECUTIVE COMPENSATION |
GULF POWER
|
| | |
COMPENSATION DISCUSSION AND ANALYSIS (CD&A) |
In this CD&A and this Form 10-K, references to the “Compensation Committee” are to the Compensation and Management Succession Committee of the Board of Directors of Southern Company. |
This section describes the compensation program for Gulf Power’s Chief Executive Officer and Chief Financial Officer in 2015, as well as each of its other three most highly compensated executive officers serving at the end of the year. |
| | |
S. W. Connally, Jr. | Chairman, President, and Chief Executive Officer | |
Xia Liu | Vice President and Chief Financial Officer | |
Jim R. Fletcher | Vice President | |
Wendell E. Smith | Vice President | |
Bentina C. Terry | Vice President | |
Also described is the compensation of Gulf Power's former Vice President and Chief Financial Officer, Richard S. Teel, who became Vice President of Fuel Services for SCS on June 1, 2015. Prior to becoming Vice President and Chief Financial Officer of Gulf Power, Ms. Liu served as Senior Vice President of Finance and Treasurer of SCS and Treasurer of Southern Company. Collectively, these officers are referred to as the named executive officers.
EXECUTIVE SUMMARY
Pay for Performance
Performance-based pay represents a substantial portion of the total direct compensation paid or granted to the named executive officers for 2015.
|
| | | | | | |
|
Salary ($)(1) |
% of Total | Annual Cash Incentive Award ($)(2) |
% of Total | Long-term Equity Incentive Award ($)(3) |
% of Total |
S. W. Connally, Jr. | 420,758 | 31% | 391,000 | 29% | 553,946 | 41% |
X. Liu | 265,380 | 44% | 188,996 | 31% | 154,865 | 25% |
R. S. Teel | 266,977 | 44% | 184,693 | 30% | 156,703 | 26% |
J. R. Fletcher | 238,711 | 43% | 169,891 | 31% | 144,315 | 26% |
W. E. Smith | 203,401 | 49% | 128,461 | 31% | 81,813 | 20% |
B. C. Terry | 278,682 | 43% | 198,007 | 31% | 168,195 | 26% |
(1) Salary is the actual amount paid in 2015.
(2) Annual Cash Incentive Award is the actual amount earned in 2015 under the Performance Pay Program based on achievement of performance goals.
(3) Long-Term Equity Incentive Award reflects the target value of the performance shares granted in 2015 under the Performance Share Program.
The executive compensation program places significant focus on rewarding performance. The program is performance-based in several respects:
Business unit financial and operational performance and Southern Company earnings per share (EPS), based on actual results as adjusted by the Compensation Committee, compared to target performance levels established early in the year, determine the actual payouts under the annual cash incentive award program (Performance Pay Program).
Southern Company's total shareholder return (TSR) compared to those of industry peers, cumulative EPS, and equity-weighted return on equity (ROE) over a three-year period lead to higher or lower payouts under the long-term equity incentive award program (Performance Share Program).
In support of this performance-based pay philosophy, Gulf Power has no general employment contracts with the named executive officers.
The pay-for-performance principles apply not only to the named executive officers but to hundreds of Gulf Power's employees. The Performance Pay Program covers almost all of the approximately 1,400 employees of Gulf Power. Performance shares were granted to 142 employees of Gulf Power. These programs engage employees and encourage alignment of their interests with Gulf Power’s customers and Southern Company’s stockholders.
Gulf Power's financial and operational goal results and Southern Company's EPS goal results for 2015, as adjusted and further described in this CD&A, are shown below: |
| | |
Financial: 125% of Target | Operational: 196% of Target | EPS: 151% of Target |
Southern Company’s annualized TSR has been: |
| | |
1-Year: -0.1% | 3-Year: 7.9% | 5-year: 9.0% |
These levels of achievement, as adjusted, resulted in payouts that were aligned with Gulf Power's and Southern Company's performance.
Compensation Philosophy
Gulf Power's compensation program is based on the following beliefs:
Employees’ commitment and performance have a significant impact on achieving business results;
Compensation and benefits offered must attract, retain, and engage employees and must be financially sustainable;
Compensation should be consistent with performance: higher pay for higher performance and lower pay for lower performance; and
Both business drivers and culture should influence the compensation and benefit program.
Based on these beliefs, the Compensation Committee believes that Gulf Power’s executive compensation program should:
Be competitive with Gulf Power’s industry peers;
Motivate and reward achievement of Gulf Power’s goals;
Be aligned with the interests of Southern Company’s stockholders and Gulf Power’s customers; and
Not encourage excessive risk-taking.
Executive compensation is targeted at the market median of industry peers, but actual compensation is primarily determined by achievement of Gulf Power’s and Southern Company's business goals. Gulf Power believes that focusing on the customer drives achievement of financial objectives and delivery of a premium, risk-adjusted total shareholder return for Southern Company’s stockholders. Therefore, short-term performance pay is based on achievement of Gulf Power’s operational and financial performance goals and Southern Company's EPS. Long-term performance pay is tied to Southern Company's TSR performance, cumulative EPS, and equity-weighted ROE.
Key Compensation Practices
• Annual pay risk assessment required by the Compensation Committee charter.
Retention by the Compensation Committee of an independent compensation consultant, Pay Governance, that provides no other services to Gulf Power or Southern Company.
Inclusion of a claw-back provision that permits the Compensation Committee to recoup performance pay from any employee if determined to have been based on erroneous results, and requires recoupment from an executive officer in the event of a material financial restatement due to fraud or misconduct of the executive officer.
• No excise tax gross-up on change-in-control severance arrangements.
Provision of limited ongoing perquisites with no income tax gross-ups for the Chairman, President, and Chief Executive Officer, except on certain relocation-related benefits.
• “No-hedging” provision in Gulf Power’s insider trading policy that is applicable to all employees.
• Policy against pledging of Southern Company stock applicable to all executive officers and directors of Southern Company,
including the Gulf Power Chief Executive Officer.
• Strong stock ownership requirements that are being met by all named executive officers.
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Establishing Executive Compensation |
The Compensation Committee establishes the Southern Company system executive compensation program. In doing so, the Compensation Committee relies on input from its independent compensation consultant, Pay Governance. The Compensation Committee also relies on input from Southern Company’s Human Resources staff and, for individual executive officer performance, from Southern Company’s and Gulf Power’s respective Chief Executive Officers. The role and information provided by each of these sources is described throughout this CD&A.
Consideration of Southern Company Stockholder Advisory Vote on Executive Compensation
The Compensation Committee considered the stockholder vote on Southern Company’s executive compensation at the Southern Company 2015 annual meeting of stockholders. In light of the significant support of Southern Company's stockholders (94% of votes cast voting in favor of the proposal) and the actual payout levels of the performance-based compensation program, the Compensation Committee continues to believe that the executive compensation program is competitive, aligned with Gulf Power's and Southern Company's financial and operational performance, and in the best interests of Gulf Power’s customers and Southern Company’s stockholders.
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ESTABLISHING MARKET-BASED COMPENSATION LEVELS |
Pay Governance develops and presents to the Compensation Committee a competitive market-based compensation level for Gulf Power's Chief Executive Officer. Southern Company's Human Resources staff develops competitive market-based compensation levels for the other Gulf Power named executive officers. The market-based compensation levels for both are developed from a size-appropriate energy services executive compensation survey database. The survey participants, listed below, are utilities with revenues of $1 billion or more.
Market data for the Chief Executive Officer position and other positions in terms of scope of responsibilities that most closely resemble the positions held by the named executive officers is reviewed. When appropriate, the market data is size-adjusted, up or down, to accurately reflect comparable scopes of responsibilities. Based on that data, a total target compensation opportunity is established for each named executive officer. Total target compensation opportunity is the sum of base salary, the annual cash incentive award at target performance level, and the long-term equity incentive award at target performance level. Actual compensation paid may be more or less than the total target compensation opportunity based on actual performance above or below target performance levels. As a result, the compensation program is designed to result in payouts that are market-appropriate given Gulf Power’s and Southern Company’s performance for the year or period.
A specified weight was not targeted for base salary, the annual cash incentive award, or the long-term equity incentive award as a percentage of total target compensation opportunities, nor did amounts realized or realizable from prior compensation serve to increase or decrease 2015 compensation amounts.
Total target compensation opportunities for senior management as a group, including the named executive officers, are managed to be at the median of the market for companies of similar size in the electric utility industry. Therefore, some executives may be paid above and others below market. This practice allows for differentiation based on time in the position, scope of responsibilities, and individual performance. The differences in the total pay opportunities for each named executive officer are based almost exclusively on the differences indicated by the market data for persons holding similar positions. Because of the use of market data from a large number of industry peer companies for positions that are not identical in terms of scope of responsibility from company to company, differences are not considered to be material and the compensation program is believed to be market-appropriate, as long as senior management as a group is within an appropriate range. Generally, compensation is considered to be within an appropriate range if it is not more or less than 15% of the applicable market data.
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AGL Resources Inc. | EP Energy Corporation | Pacific Gas & Electric Company |
Allete, Inc. | EQT Corporation | Pepco Holdings, Inc. |
Alliant Energy Corporation | Eversource International | Pinnacle West Capital Corporation |
Ameren Corporation | Exelon Corporation | PNM Resources Inc. |
American Electric Power Company, Inc. | FirstEnergy Corp. | Portland General Electric Company |
American Water Works Company, Inc. | First Solar Inc. | PPL Corporation |
Areva Inc. | GE Energy | Public Service Enterprise Group Inc. |
Atmos Energy Corporation | Iberdrola USA, Inc. | Puget Sound Energy, Inc. |
Austin Energy | Idaho Power Company | Questar Corporation |
Avista Corporation | Integrys Energy Group, Inc. | Salt River Project |
Bg US Services, Inc. | Invenergy LLC | Santee Cooper |
Black Hills Corporation | JEA | SCANA Corporation |
Boardwalk Pipeline Partners, L.P. | Kinder Morgan Energy Partners, L.P. | Sempra Energy |
Calpine Corporation | Laclede Group, Inc. | Southwest Gas Corporation |
CenterPoint Energy, Inc. | LG&E and KU Energy LLC | Spectra Energy Corp. |
Cleco Corporation | Lower Colorado River Authority | TECO Energy, Inc. |
CMS Energy Corporation | MDU Resources Group, Inc. | Tennessee Valley Authority |
Consolidated Edison, Inc. | Monroe Energy | Tervita Corporation |
Dominion Resources, Inc. | National Grid USA | The AES Corporation |
DTE Energy Company | Nebraska Public Power District | The Babcock & Wilcox Company |
Duke Energy Corporation | New Jersey Resources Corporation | The Williams Companies, Inc. |
Dynegy Inc. | New York Power Authority | TransCanada Corporation |
Edison International | NextEra Energy, Inc. | Tri-State Generation & Transmission Association, Inc. |
ElectriCities of North Carolina | NiSource Inc. |
Energen Corporation | NorthWestern Corporation | UGI Corporation |
Energy Future Holdings Corp. | NOVA Chemicals Corporation | UIL Holdings |
Energy Solutions, Inc. | NRG Energy, Inc. | UNS Energy Corporation |
Energy Transfer Partners, L.P. | OGE Energy Corp. | Vectren Corporation |
ENGIE Energy North America | Omaha Public Power District | Westar Energy, Inc. |
EnLink Midstream | Oncor Electric Delivery Company LLC | Wisconsin Energy Corporation |
Entergy Corporation | ONE Gas, Inc. | Xcel Energy Inc. |
Executive Compensation Program
The primary components of the 2015 executive compensation program include:
Short-term compensation
Long-term compensation
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◦ | Performance Share Program |
Benefits
The performance-based compensation components are linked to Gulf Power's financial and operational performance as well as Southern Company's financial and stock price performance, including TSR, EPS, and ROE. The executive compensation program is approved by the Compensation Committee, which consists entirely of independent directors of Southern Company. The Compensation Committee believes that the executive compensation program is a balanced program that provides market-based compensation and motivates and rewards performance.
2015 Base Salary
Most employees, including all of the named executive officers, received base salary increases in 2015.
With the exception of Southern Company executive officers, including Mr. Connally, base salaries for all Southern Company system officers are within a position level with a base salary range that is established by Southern Company Human Resources staff using the market data described above. Each officer is within one of these established position levels based on the scope of responsibilities that most closely resemble the positions included in the market data described above. The base salary level for individual officers is set within the applicable pre-established range. Factors that influence the specific base salary level within the range include the need to retain an experienced team, internal equity, time in position, and individual performance. Individual performance includes the degree of competence and initiative exhibited and the individual’s relative contribution to the achievement of financial and operational goals in prior years.
Base salaries are reviewed annually in February and changes are made effective March 1. The base salary levels established early in the year for the named executive officers were set within the applicable position level salary range and were recommended by the individual named executive officer’s supervisor and approved by Southern Company's Chief Executive Officer. Mr. Connally's base salary was approved by the Compensation Committee.
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| March 1, 2014 Base Salary ($) | March 1, 2015 Base Salary ($) |
S. W. Connally, Jr. | 398,242 | 426,119 |
X. Liu | 241,942 | 258,124 |
R. S. Teel | 253,540 | 261,168 |
J. R. Fletcher | 211,255 | 240,470 |
W. E. Smith | 187,314 | 204,555 |
B. C. Terry | 272,039 | 280,264 |
Ms. Liu was Senior Vice President of Finance and Treasurer of SCS and Treasurer of Southern Company prior to her promotion to Vice President and Chief Financial Officer at Gulf Power on June 1, 2015. At that time, her base salary was increased to $273,611.
When Mr. Teel was promoted from Vice President and Chief Financial Officer of Gulf Power to Vice President of Fuel Services at SCS on June 1, 2015, his base salary was increased to $274,227.
2015 Performance-Based Compensation
This section describes short-term and long-term performance-based compensation for 2015.
Achieving Operational and Financial Performance Goals - The Guiding Principle for Performance-Based Compensation
The Southern Company system’s number one priority is to continue to provide customers outstanding reliability and superior service at reasonable prices while achieving a level of financial performance that benefits Southern Company’s stockholders in the short and long term. Operational excellence and business unit and Southern Company financial performance are integral to the achievement of business results that benefit customers and stockholders.
Therefore, in 2015, Gulf Power strove for and rewarded:
Continuing industry-leading reliability and customer satisfaction, while maintaining reasonable retail prices;
• Meeting energy demand with the best economic and environmental choices;
• Long-term, risk-adjusted Southern Company TSR;
• Achieving net income goals to support the Southern Company financial plan and dividend growth; and
• Financial integrity - an attractive risk-adjusted return and sound financial policy.
The performance-based compensation program is designed to encourage achievement of these goals.
The Southern Company Chief Executive Officer, with the assistance of Southern Company’s Human Resources staff, recommended to the Compensation Committee the program design and award amounts for senior management, including the named executive officers.
2015 Annual Performance-Based Pay Program
Annual Performance Pay Program Highlights
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Added individual performance goals for the Chief Executive Officer•
Rewards achievement of annual performance goals; performance results can range from 0% to 200% of target, based on actual level of goal achievement◦
EPS: earned at 151% of target◦
Net Income: earned at 125% of target◦
Operations: earned at 196% of target•
2015 Payout: Exceeded target performance◦
Chief Executive Officer payout at 153% of target◦
Average of the other named executive officers' payout at 155% of target
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Overview of Program Design
Almost all employees of Gulf Power, including the named executive officers, are participants.
The performance goals are set at the beginning of each year by the Compensation Committee and include financial and operational goals for all employees. In setting goals, the Compensation Committee relies on information on financial and operational goals from the Finance Committee and the Nuclear/Operations Committee of the Southern Company Board of Directors, respectively.
Business Unit Financial Goal: Net Income
For Southern Company’s traditional operating companies, including Gulf Power, and Southern Power, the business unit financial performance goal is net income. There is no separate net income goal for Southern Company as a whole. Overall Southern Company performance is determined by the equity-weighted average of the business unit net income goal payouts.
Business Unit Operational Goals: Varies by business unit
For Southern Company’s traditional operating companies, including Gulf Power, operational goals are customer satisfaction, safety, major projects (Georgia Power and Mississippi Power), culture, transmission and distribution system reliability, and plant availability. Each of these operational goals is explained in more detail under Goal Details below. The level of achievement for each operational goal is determined according to the respective performance schedule, and the total operational goal performance is determined by the weighted average result. Each business unit has its own operational goals.
Southern Company Financial Goal: EPS
EPS is defined as Southern Company’s net income from ongoing business activities divided by average shares outstanding during the year, as adjusted and approved by the Compensation Committee. The EPS performance measure is applicable to all participants in the Performance Pay Program.
Individual Performance Goals for the Chief Executive Officer
Beginning in 2015, the Performance Pay Program incorporates individual goals for all executive officers of Southern Company, including Mr. Connally. The Compensation Committee sets the individual goals for Mr. Connally and evaluates his performance at the end of the year. The individual goals account for 10% of Mr. Connally's Performance Pay Program goals.
Under the terms of the program, no payout can be made if events occur that impact Southern Company's financial ability to fund the Southern Company common stock (Common Stock) dividend.
Goal Details
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Operational Goals | Description | Why It Is Important |
Customer Satisfaction | Customer satisfaction surveys evaluate performance. The survey results provide an overall ranking for each traditional operating company, including Gulf Power, as well as a ranking for each customer segment: residential, commercial, and industrial. | Customer satisfaction is key to operations. Performance of all operational goals affects customer satisfaction. |
Safety | Southern Company's Target Zero program is focused on continuous improvement in striving for a safe work environment. The performance is measured by the applicable company's ranking, as compared to peer utilities in the Southeastern Electric Exchange. | Essential for the protection of employees, customers, and communities. |
Major Projects - Plant Vogtle Units 3 and 4 and Kemper IGCC | The Southern Company system is committed to the safe, compliant, and high-quality construction and licensing of two new nuclear generating units under construction at Plant Vogtle Units 3 and 4 and the Kemper IGCC, as well as excellence in transition to operations and prudent decision-making related to these two major projects. A combination of subjective and objective measures is considered in assessing the degree of achievement. Annual goals are established that are designed to achieve long-term project completion with a focus on validating technology and providing clean, reliable operation. An executive review committee is in place for each project to assess progress. Final assessments for each project are approved by either Southern Company’s Chief Executive Officer or Southern Company’s Chief Operating Officer and confirmed by the Nuclear/Operations Committee of Southern Company. | Strategic projects enable the Southern Company system to expand capacity to provide clean, safe, reliable, and affordable energy to customers across the region. Long-term projects are accomplished through achievement of annual goals over the life cycle of the project. |
Culture | The culture goal seeks to improve Gulf Power's inclusive workplace. This goal includes measures for work environment (employee satisfaction survey), representation of minorities and females in leadership roles (subjectively assessed), and supplier diversity. | Supports workforce development efforts and helps to assure diversity of suppliers. |
Reliability | Transmission and distribution system reliability performance is measured by the frequency and duration of outages. Performance targets for reliability are set internally based on recent historical performance. | Reliably delivering power to customers is essential to Gulf Power's operations. |
Availability | Peak season equivalent forced outage rate is an indicator of availability and efficient generation fleet operations during the months when generation needs are greatest. Availability is measured as a percentage of the hours of forced outages out of the total generation hours. | Availability of sufficient power during peak season fulfills the obligation to serve and provide customers with the least cost generating resources. |
Nuclear Plant Operations | Nuclear plant performance is evaluated by measuring nuclear safety as rated by independent industry evaluators, as well as by a quantitative score comprised of various plant performance indicators. Plant reliability and operational availability are measured as a percentage of time the nuclear plant is operating. The reliability and availability metrics take generation reductions associated with planned outages into consideration. | Safe and efficient operation of the nuclear fleet is important for delivering clean energy at a reasonable price. |
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Financial Performance Goals | Description | Why It Is Important |
EPS | Southern Company's net income from ongoing business activities divided by average shares outstanding during the year. | Supports commitment to provide Southern Company's stockholders solid, risk-adjusted returns and to support and grow the dividend. |
Net Income | For the traditional operating companies, including Gulf Power, and Southern Power, the business unit financial performance goal is net income after dividends on preferred and preference stock.
Overall corporate performance is determined by the equity-weighted average of the business unit net income goal payouts.
| Supports delivery of Southern Company stockholder value and contributes to Gulf Power's and Southern Company's sound financial policies and stable credit ratings. |
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Individual Performance Goals (Mr. Connally only) | Description | Why It Is Important |
Individual Factors | Focus on overall business performance as well as factors including leadership development, succession planning and fostering the culture and diversity of the organization. | Individual goals provide the Compensation Committee the ability to balance quantitative results with qualitative inputs by focusing on both business performance and behavioral aspects of leadership that lead to sustainable long-term growth. |
The range of business unit and Southern Power net income goals and Southern Company EPS goals for 2015 is shown below.
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Level of Performance | Alabama Power Net Income ($, in millions) | Georgia Power Net Income ($, in millions) | Gulf Power Net Income ($, in millions) | Mississippi Power Net Income ($, in millions) | Southern Power Net Income ($, in millions) | Southern Company EPS ($) |
Maximum | 821.0 | 1,312.0 | 158.0 | 212.2 | 225.0 | 2.96 |
Target | 763.0 | 1,208.0 | 144.6 | 190.0 | 165.0 | 2.82 |
Threshold | 704.0 | 1,103.0 | 131.3 | 167.8 | 105.0 | 2.68 |
The Compensation Committee approves threshold, target, and maximum performance levels for each of the operational goals. If goal achievement is below threshold, there is no payout associated with the applicable goal.
Calculating Payouts
All of the named executive officers are paid based on Southern Company EPS performance. With the exception of Ms. Liu and Mr. Teel, all of the named executive officers are paid based on Gulf Power net income and operational performance. Ms. Liu's payout is prorated based on the time she was employed at SCS and at Gulf Power. Mr. Teel's payout is prorated based on the amount of time he was employed at Gulf Power and SCS.
Actual 2015 goal achievement is shown in the following tables.
Operational Goal Results
Gulf Power (Mses. Liu and Terry and Messrs. Connally, Teel, Smith, and Fletcher)
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Goal | Achievement |
Customer Satisfaction | Maximum |
Safety | Near maximum |
Culture | Significantly above target |
Reliability | Maximum |
Availability | Maximum |
Total Gulf Power Operational Goal Performance Factor | 196% |
Southern Company Corporate & Services (Ms. Liu and Mr. Teel)
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Goal | Achievement |
Customer Satisfaction | Maximum |
Safety | Slightly below target |
Major Projects - Plant Vogtle Units 3 and 4 annual objectives | Above target |
Major Projects - Kemper IGCC annual objectives | At target |
Culture | Above target |
Reliability | Below target |
Availability | Maximum |
Total Southern Company Corporate & Services Operational Goal Performance Factor | 147% |
Financial Performance Goal Results
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Goal | Result | Achievement Percentage (%) |
Gulf Power Net Income | $148.0 | 125 |
Southern Power Net Income | $210.0 | 184 |
Corporate Net Income Result | Equity-Weighted Average | 145 |
EPS (from ongoing business activities) as adjusted by the Compensation Committee | $2.86* | 151 |
*The Compensation Committee may make adjustments, both positive and negative, to goal achievement for purposes of determining payouts. Southern Company's reported 2015 adjusted EPS result was $2.89. The reported adjusted EPS result excludes the impact of charges related to the Kemper IGCC, acquisition costs related to the Merger, and the settlement costs related to MC Asset Recovery, LLC. In addition to the these three items, the Compensation Committee approved a further adjustment for the earnings impact related to the termination of an asset purchase agreement for a portion of the Kemper IGCC. This additional adjustment reduced the Southern Company EPS result for Performance Pay Program compensation purposes from $2.89 to $2.86.
A total performance factor is determined by adding the applicable business unit financial and operational goal performance and the EPS results and dividing by three, except for Mr. Connally. For Mr. Connally, the business unit financial and operational goal performance and EPS results are worth 30% each of the total performance factor, while his individual performance goal result is worth the remaining 10%. The total performance factor is multiplied by the target Performance Pay Program opportunity to determine the payout for each named executive officer.
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| Southern Company EPS Result (%) | Business Unit Financial Goal Result (%) | Business Unit Operational Goal Result (%) | Individual Goal Result (%) | Total Performance Factor (%) |
S. W. Connally, Jr. | 151 | 125 | 196 | 112 | 153 |
X. Liu(1) | 151 | 145/125 | 147/196 | N/A | 148/157 |
R. S. Teel(2) | 151 | 125/145 | 196/147 | N/A | 157/148 |
J. R. Fletcher | 151 | 125 | 196 | N/A | 157 |
W. E. Smith | 151 | 125 | 196 | N/A | 157 |
B. C. Terry | 151 | 125 | 196 | N/A | 157 |
(1) Ms. Liu was Senior Vice President of Finance and Treasurer of SCS and Treasurer of Southern Company until her promotion to Vice President and Chief Financial Officer of Gulf Power on June 1, 2015. Under the terms of the program, Ms. Liu's Performance Pay Program results were prorated based on the time she served at each company.
(2) Mr. Teel was Gulf Power's Vice President and Chief Financial Officer until his promotion to Vice President of Fuel Services for SCS on June 1, 2015. Under the terms of the program, Mr. Teel's Performance Pay Program results were prorated based on the time he served at each company.
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| Target Annual Performance Pay Program Opportunity (% of base salary) | Target Annual Performance Pay Program Opportunity ($) | Total Performance Factor (% of target) | Actual Annual Performance Pay Program Payout ($) |
S. W. Connally, Jr. | 60 | 255,671 | 153 | 391,000 |
X. Liu | 45 | 123,125 | 148/157 | 188,996 |
R. S. Teel | 45 | 123,402 | 157/148 | 184,693 |
J. R. Fletcher | 45 | 108,211 | 157 | 169,891 |
W. E. Smith | 40 | 81,822 | 157 | 128,461 |
B. C. Terry | 45 | 126,119 | 157 | 198,007 |
Long-Term Performance-Based Compensation
2015 Long-Term Pay Program Highlights
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Moved away from granting stock options; 100% of award is in performance shares subject to achievement of performance goals over a three-year performance period◦
Expanded performance goals to include three performance measurements (TSR, EPS, and ROE)◦
Represents 100% of long-term target value▪
TSR relative to industry peers (50%)▪
Cumulative three-year EPS (25%)▪
Equity-weighted ROE (25%)◦
Three-year performance period from 2015 through 2017◦
Performance results can range from 0% to 200% of target◦
Paid in Common Stock at the end of the performance period; accrued dividends only received if and when award is earned |
Since 2010, the long-term performance-based compensation program has included two components: stock options and performance shares. In early 2015, the Compensation Committee made some changes to the long-term performance-based compensation program that followed from the focus on continuously refining the executive compensation program to more effectively align executive pay with performance and reflect best compensation practices. Beginning with the 2015 grant, the Compensation Committee moved away from granting stock options and shifted the long-term equity award to 100% performance shares. The new structure maintains the
three-year performance cycle but expands the performance metrics from one to three metrics: relative TSR (50% weighting), cumulative three-year EPS (25% weighting), and equity-weighted ROE (25% weighting).
2015-2017 Performance Share Program Grant
Performance shares are denominated in units, meaning no actual shares are issued on the grant date. A grant date fair value per unit was determined. For the portion of the grant attributable to the relative TSR goal, the value per unit was $46.43. For the portion of the grant attributable to the cumulative three-year EPS and equity-weighted ROE goals, the value per unit was $47.79. A target number of performance shares are granted to a participant, based on the total target value as determined as a percentage of a participant's base salary, which varies by grade level. The total target value for performance share units is divided by the value per unit to determine the number of performance share units granted to each participant, including the named executive officers. Each performance share unit represents one share of Common Stock.
The following table shows the grant date fair value and target number of the long-term equity incentive awards granted in 2015.
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| Target Value (% of base salary) | Relative TSR (50%) | Cumulative EPS (25%) | Equity-Weighted ROE (25%) | Total Long-Term Grant |
| Grant Date Fair Value ($) | Target Number of Shares (#) | Grant Date Fair Value ($) | Target Number of Shares (#) | Grant Date Fair Value ($) | Target Number of Shares (#) | Grant Date Fair Value ($) | Target Number of Shares (#) |
S. W. Connally, Jr. | 130 | 276,955 | 5,965 | 138,495 | 2,898 | 138,495 | 2,898 | 553,946 | 11,761 |
X. Liu | 60 | 77,445 | 1,668 | 38,710 | 810 | 38,710 | 810 | 154,865 | 3,288 |
R. S. Teel | 60 | 78,327 | 1,687 | 39,188 | 820 | 39,188 | 820 | 156,703 | 3,327 |
J. R. Fletcher | 60 | 72,152 | 1,554 | 36,081 | 755 | 36,081 | 755 | 144,315 | 3,064 |
W. E. Smith | 40 | 40,905 | 881 | 20,454 | 428 | 20,454 | 428 | 81,813 | 1,737 |
B. C. Terry | 60 | 84,085 | 1,811 | 42,055 | 880 | 42,055 | 880 | 168,195 | 3,571 |
The award includes three performance measures for the 2015-2017 performance period: relative TSR (50% weighting), cumulative three-year EPS (25% weighting), and equity-weighted ROE (25% weighting).
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Goal | What it Measures | Why it’s Important | How it’s Calculated |
Relative TSR | Stock price performance plus dividends relative to peer companies | Aligns employee pay with investor returns relative to peers | (Common Stock price at end of year 3 - common stock price at start of year 1 + dividends paid and reinvested) / Common Stock price at start of year 1
Result compared to similar calculation for peer group
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Cumulative EPS | Cumulative EPS over the three-year performance period | Aligns employee pay with Southern Company's earnings growth | EPS Year 1 + EPS Year 2 + EPS Year 3 = Cumulative EPS Result |
Equity-Weighted ROE | Equity-weighted ROE of the traditional operating companies | Aligns employee pay with Southern Company’s ability to maximize return on capital invested | Average equity-weighted ROE of each traditional operating company during three-year performance period multiplied by the average equity weighting of each during the period |
For each of the performance measures, a threshold, target and maximum goal was set at the beginning of the performance period. |
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| Relative TSR Performance (50% weighting) | Cumulative EPS Performance (25% weighting) | Equity-Weighted ROE Performance (25% weighting) | Payout (% of Performance Share Units Paid) |
Maximum | 90th percentile or higher | $9.16 | 5.9% | 200% |
Target | 50th percentile | $8.66 | 5.1% | 100% |
Threshold | 10th percentile | $8.16 | 4.7% | 0% |
The EPS and ROE goals are also both subject to a credit quality threshold requirement that encourages the maintenance of adequate credit ratings to provide an attractive return to investors. If the primary credit rating falls below investment grade at the end of the three-year performance period, the payout for the EPS and ROE goals will be reduced to zero.
Total stockholder return is measured relative to a peer group of companies that are believed to be most similar to Southern Company in both business model and investors. The peer group is subject to change based on merger and acquisition activity.
TSR Performance Share Peer Group for 2015 - 2017 Performance Period
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Alliant Energy Corporation | OGE Energy Corporation |
Ameren Corporation | Pepco Holdings, Inc. |
American Electric Power Company, Inc. | PG&E Corporation |
CMS Energy Corporation | Pinnacle West Capital Corporation |
Consolidated Edison, Inc. | PPL Corporation |
DTE Energy Company | SCANA Corporation |
Duke Energy Corporation | Westar Energy Inc. |
Edison International | Wisconsin Energy Corporation |
Entergy Corporation | Xcel Energy Inc. |
Eversource Energy | |
Other Details about the Program
Performance shares are not earned until the end of the three-year performance period and after certification of the results by the Compensation Committee. A participant can earn from 0% to 200% of the target number of performance shares granted at the beginning of the performance period based solely on achievement of the performance goals over the three-year performance period. Dividend equivalents are credited during the three-year performance period but are only paid out if and when the award is earned. If no performance shares are earned, then no dividends are paid out. Payout for performance between points will be interpolated on a straight-line basis.
A participant who terminates employment, other than due to retirement or death, forfeits all unearned performance shares. Participants who retire during the performance period will receive the full amount of performance shares actually earned at the end of the three-year period. Performance shares will be prorated based on the number of months employed during the performance period for a participant who dies during the performance period.
The Compensation Committee retains the discretion to approve adjustments in determining actual performance goal achievement.
2013-2015 Payouts
Performance share grants were made in 2013 with a three-year performance period that ended on December 31, 2015. Based on Southern Company’s TSR achievement relative to that of the Philadelphia Utility Index (55% payout) and the custom peer group (0% payout), the payout percentage was 28% of target, which is the average of the results for the two peer groups.
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Philadelphia Utility Index |
AEP | DTE | Exelon |
AES | Duke | First Energy |
Ameren | Edison | NextEra |
CenterPoint | El Paso Electric | PG&E |
ConEd | Entergy | PSEG |
Covanta | Eversource Energy | Xcel |
Dominion | | |
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Custom Peer Group |
AEP | Edison |
Alliant Energy | Eversource Energy |
Ameren | PG&E |
CMS | Pinnacle West |
ConEd | Scana |
DTE | Wisconsin Energy |
Duke | Xcel |
Actual payouts were significantly less than the target grant date fair value due to below-target relative TSR performance.
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| Target Performance Shares (#) | Target Value of Performance Shares ($) | Performance Shares Earned (#) | Value of Performance Shares Earned(1) ($) |
S. W. Connally, Jr. | 7,235 | 293,018 | 2,026 | 94,797 |
X. Liu | 1,299 | 52,610 | 364 | 17,032 |
R. S. Teel | 2,188 | 88,614 | 613 | 28,682 |
J. R. Fletcher | 1,209 | 48,965 | 339 | 15,862 |
W. E. Smith | 650 | 26,325 | 182 | 8,516 |
B. C. Terry | 2,348 | 95,094 | 657 | 30,741 |
(1) Calculated using a stock price of $46.79, which was the closing price on December 31, 2015, the date the performance shares vested.
Timing of Performance-Based Compensation
The establishment of performance-based compensation goals and the granting of equity awards are not timed to coincide with the release of material, non-public information.
Southern Excellence Awards
Mr. Teel received a discretionary award in the amount of $5,000 while employed at SCS in recognition of his leadership and superior performance related to due diligence activities performed in connection with the Merger.
Retirement and Severance Benefits
Certain post-employment compensation is provided to employees, including the named executive officers, consistent with Gulf Power's goal of providing market-based compensation and benefits.
Retirement Benefits
Substantially all employees of Gulf Power participate in the funded Pension Plan after completing one year of service. Normal retirement benefits become payable when participants attain age 65 and complete five years of participation. Gulf Power also provides unfunded benefits that count salary and annual Performance Pay Program payouts that are ineligible to be counted under the Pension Plan. See the Pension Benefits table and accompanying information for more pension-related benefits information.
Gulf Power and its affiliates also provide supplemental retirement benefits to certain employees that were first employed by Gulf Power, or an affiliate of Gulf Power, in the middle of their careers. Gulf Power has had a supplemental retirement agreement (SRA) with Ms. Terry since 2010. Prior to her employment with the Southern Company system, Ms. Terry provided legal services to Southern Company's subsidiaries. Ms. Terry's agreement provides retirement benefits as if she was employed an additional 10 years. Ms. Terry must remain employed at Gulf Power or an affiliate of Gulf Power for 10 years from the effective date of the SRA before vesting in the benefits. This agreement provides a benefit which recognizes the expertise she brought to Gulf Power and provides a strong retention incentive to remain with Gulf Power, or one of its affiliates, for the vesting period and beyond.
Gulf Power also provides the Deferred Compensation Plan, which is an unfunded plan that permits participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement, disability, death, or other separation from service. Up to 50% of base salary and up to 100% of performance-based non-equity compensation may be deferred at the election of eligible employees. All of the named executive officers are eligible to participate in the Deferred Compensation Plan.
Change-in-Control Protections
Change-in-control protections, including severance pay and, in some situations, vesting or payment of long-term performance-based awards, are provided upon a change in control of Southern Company or Gulf Power coupled with an involuntary termination not for cause or a voluntary termination for “Good Reason.” This means there is a “double trigger” before severance benefits are paid; i.e., there must be both a change in control and a termination of employment. Severance payment amounts are two times salary plus target Performance Pay Program opportunity for Mr. Connally and one times salary plus Performance Pay Program opportunity for the other named executive officers. No excise tax gross-up would be provided. Change-in-control protections allow executive officers to focus on potential transactions that are in the best interest of shareholders.
Perquisites
Gulf Power provides limited perquisites to its executive officers, including the named executive officers, consistent with Gulf Power's goal of providing market-based compensation and benefits. The perquisites provided in 2015, including amounts, are described in detail in the information accompanying the Summary Compensation Table. No tax assistance is provided on perquisites for the Chairman, President, and Chief Executive Officer, except on certain relocation-related benefits.
OTHER COMPENSATION POLICIES
|
|
Executive Stock Ownership Requirements |
Officers of Gulf Power that are in a position of Vice President or above are subject to stock ownership requirements. All of the named executive officers are covered by the requirements. Ownership requirements further align the interest of officers and Southern Company’s stockholders by promoting a long-term focus and long-term share ownership. The types of ownership arrangements counted toward the requirements are shares owned outright, those held in Southern Company-sponsored plans, and Common Stock accounts in the Deferred Compensation Plan and the Supplemental Benefit Plan. One-third of vested Southern Company stock options may be counted, but, if so, the ownership requirement is doubled. The ownership requirement is reduced by one-half at age 60.
The requirements are expressed as a multiple of base salary as shown below.
|
| | |
| Multiple of Salary without
Counting Stock Options
| Multiple of Salary Counting
1/3 of Vested Options
|
S. W. Connally, Jr. | 3 Times | 6 Times |
X. Liu | 2 Times | 4 Times |
R. S. Teel | 2 Times | 4 Times |
J. R. Fletcher | 2 Times | 4 Times |
W. E. Smith | 1 Times | 2 Times |
B. C. Terry | 2 Times | 4 Times |
Newly-elected officers have approximately five years from the date of their election to meet the applicable ownership requirement. Newly-promoted officers have approximately five years from the date of their promotion to meet the increased ownership requirement. All of the named executive officers are meeting their respective ownership requirements.
|
|
Policy on Recovery of Awards |
Southern Company’s Omnibus Incentive Compensation Plan provides that, if Southern Company or Gulf Power is required to prepare an accounting restatement due to material noncompliance as a result of misconduct, and if an executive officer of Gulf Power knowingly or grossly negligently engaged in or failed to prevent the misconduct or is subject to automatic forfeiture under the Sarbanes-Oxley Act of 2002, the executive officer must repay Southern Company the amount of any payment in settlement of awards earned or accrued during the 12-month period following the first public issuance or filing that was restated.
|
|
Policy Regarding Hedging and Pledging of Common Stock |
Southern Company’s insider trading policy provides that employees, officers, and directors will not trade Southern Company options on the options market and will not engage in short sales. In early 2016, Southern Company added a "no pledging" provision to the insider trading policy that prohibits pledging of Common Stock for all Southern Company directors and executive officers, including the Gulf Power President and Chief Executive Officer.
|
|
COMPENSATION COMMITTEE REPORT |
The Compensation Committee met with management to review and discuss the CD&A. Based on such review and discussion, the Compensation Committee recommended to the Southern Company Board of Directors that the CD&A be included in Gulf Power's Annual Report on Form 10-K for the fiscal year ended December 31, 2015.
Members of the Compensation Committee:
Henry A. Clark III, Chair
David J. Grain
Veronica M. Hagen
William G. Smith, Jr.
Steven R. Specker
SUMMARY COMPENSATION TABLE
The Summary Compensation Table shows the amount and type of compensation received or earned in 2013, 2014, and 2015 by the named executive officers, except as noted below.
|
| | | | | | | | | | | | | | | | | |
Name and Principal Position (a) | Year (b) | Salary ($) (c) | Bonus ($) (d) | Stock Awards ($) (e) | Option Awards ($) (f) | Non-Equity Incentive Plan Compensation ($) (g) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (h) | All Other Compensation ($) (i) | Total ($) (j) |
| | | | | | | | | |
S. W. Connally, Jr. President, Chief Executive Officer, and Director | 2015 | 420,758 |
| — |
| 553,946 |
| — |
| 391,000 |
| 160,338 |
| 30,485 |
| 1,556,527 |
|
2014 | 393,907 |
| — |
| 310,606 |
| 207,086 |
| 339,302 |
| 496,800 |
| 25,948 |
| 1,773,649 |
|
2013 | 372,977 |
| — |
| 293,018 |
| 195,363 |
| 164,557 |
| 54,607 |
| 25,602 |
| 1,106,124 |
|
X. Liu Vice President and Chief Financial Officer | 2015 | 265,380 |
| — |
| 154,865 |
| — |
| 188,996 |
| 59,936 |
| 283,417 |
| 952,594 |
|
R. S. Teel Former Vice President and Chief Financial Officer | 2015 | 266,977 |
| 5,000 |
| 156,703 |
| — |
| 184,693 |
| 35,467 |
| 253,830 |
| 902,670 |
|
2014 | 252,110 |
| — |
| 91,260 |
| 60,841 |
| 161,989 |
| 157,002 |
| 17,166 |
| 740,368 |
|
2013 | 244,903 |
| — |
| 88,614 |
| 59,101 |
| 80,895 |
| — |
| 17,004 |
| 490,517 |
|
J. R. Fletcher | 2015 | 238,711 |
| — |
| 144,315 |
| — |
| 169,891 |
| 48,436 |
| 120,417 |
| 721,770 |
|
Vice President | 2014 | 224,547 |
| 25,045 |
| 50,679 |
| 33,801 |
| 149,633 |
| 273,148 |
| 89,971 |
| 846,824 |
|
W. E. Smith | 2015 | 203,401 |
| — |
| 81,813 |
| — |
| 128,461 |
| 42,181 |
| 144,040 |
| 599,896 |
|
Vice President | | | | | | | | | |
B. C. Terry | 2015 | 278,682 |
| — |
| 168,195 |
| — |
| 198,007 |
| 34,345 |
| 19,421 |
| 698,650 |
|
Vice President | 2014 | 270,543 |
| — |
| 97,904 |
| 65,287 |
| 173,833 |
| 245,578 |
| 17,664 |
| 870,809 |
|
| 2013 | 262,809 |
| — |
| 95,094 |
| 63,419 |
| 86,809 |
| — |
| 16,735 |
| 524,866 |
|
Column (a)
Ms. Liu and Mr. Smith first became named executive officers in 2015.
Column (d)
The amount shown for 2015 for Mr. Teel represents a Southern Excellence Award as described in the CD&A.
Column (e)
This column does not reflect the value of stock awards that were actually earned or received in 2015. Rather, as required by applicable rules of the SEC, this column reports the aggregate grant date fair value of performance shares granted in 2015. The value reported is based on the probable outcome of the performance conditions as of the grant date, using a Monte Carlo simulation model (50% of grant value) and the closing price of Common Stock on the grant date (50% of grant value). No amounts will be earned until the end of the three-year performance period on December 31, 2017. The value then can be earned based on performance ranging from 0 to 200%, as established by the Compensation Committee. The aggregate grant date fair value of the performance shares granted in 2015 to Mses. Liu and Terry and Messrs. Connally, Teel, Fletcher, and Smith, assuming that the highest level of performance is achieved, is $309,730, $336,390, $1,107,892, $313,406, $288,630, and $163,626, respectively (200% of the amount shown in the table). See Note 8 to the financial statements of Gulf Power in Item 8 herein for a discussion of the assumptions used in calculating these amounts.
Column (f)
Stock options were not granted in 2015. This column reports the aggregate grant date fair value of stock options granted in 2013 and 2014.
Column (g)
The amounts in this column are the payouts under the annual Performance Pay Program. The amount reported for 2015 is for the one-year performance period that ended on December 31, 2015. The Performance Pay Program is described in detail in the CD&A.
Column (h)
This column reports the aggregate change in the actuarial present value of each named executive officer's accumulated benefit under the Pension Plan and the supplemental pension plans (collectively, Pension Benefits) as of December 31, 2013, 2014, and 2015. The Pension Benefits as of each measurement date are based on the named executive officer's age, pay, and service accruals and the plan provisions applicable as of the measurement date. The actuarial present values as of each measurement date reflect the assumptions Gulf Power selected for cost purposes as of that measurement date; however, the named executive officers were assumed to remain employed at Gulf Power or any Southern Company subsidiary until their benefits commence at the pension plans' stated normal retirement date, generally age 65. As a result, the amounts in column (h) related to Pension Benefits represent the combined impact of several factors: growth in the named executive officer's Pension Benefits over the measurement year; impact on the total present values of one year shorter discounting period due to the named executive officer being one year closer to normal retirement; impact on the total present values attributable to changes in assumptions from measurement date to measurement date; and impact on the total present values attributable to plan changes between measurement dates.
For more information about the Pension Benefits and the assumptions used to calculate the actuarial present value of accumulated benefits as of December 31, 2015, see the information following the Pension Benefits table. This column also reports above-market earnings on deferred compensation under the Deferred Compensation Plan (DCP). However, there were no above-market earnings on deferred compensation in the years reported.
Column (i)
This column reports the following items: perquisites; tax reimbursements; employer contributions to the Southern Company Employee Savings Plan (ESP), which is a tax-qualified defined contribution plan intended to meet requirements of Section 401(k) of the Internal Revenue Code; and employer contributions under the Southern Company Supplemental Benefit Plan (Non-Pension Related) (SBP). The SBP is described more fully in the information following the Nonqualified Deferred Compensation table.
The amounts reported for 2015 are itemized below.
|
| | | | | | | | | | |
|
Perquisites ($) |
Tax Reimbursements ($) |
ESP ($) |
SBP ($) |
Total ($) |
S. W. Connally, Jr. | 9,069 |
| — | 13,472 |
| 7,944 |
| 30,485 |
|
X. Liu | 257,862 |
| 12,281 |
| 13,255 |
| 19 |
| 283,417 |
|
R. S. Teel | 205,087 |
| 35,127 |
| 13,515 |
| 101 |
| 253,830 |
|
J. R. Fletcher | 99,741 |
| 8,502 |
| 12,174 |
| — | 120,417 |
|
W. E. Smith | 131,102 |
| 2,558 |
| 8,817 |
| 1,563 |
| 144,040 |
|
B. C. Terry | 7,055 |
| 189 |
| 11,479 |
| 698 |
| 19,421 |
|
Description of Perquisites
Personal Financial Planning is provided for most officers of Gulf Power, including all of the named executive officers. Gulf Power pays for the services of a financial planner on behalf of the officers, up to a maximum amount of $8,700 per year, after the initial year that the benefit is provided. In the initial year, the allowed amount is $15,000. Gulf Power also provides a five-year allowance of $6,000 for estate planning and tax return preparation fees.
Relocation Benefits are provided to cover the costs associated with geographic relocation. In 2015, Ms. Liu received relocation-related benefits in the amount of $248,985 in connection with her 2015 relocation from Atlanta, Georgia to Pensacola, Florida. In 2015, Mr. Teel received relocation-related benefits in the amount of $196,980 in connection with his 2015 relocation from Pensacola to Birmingham, Alabama. In 2015, Mr. Fletcher received relocation-related benefits in the amount of $92,950 in connection with his 2014 relocation from Atlanta to Pensacola. In 2015, Mr. Smith received relocation-related benefits in the amount of $127,866 in connection with his 2014 relocation from Athens, Georgia to Pensacola. These amounts were for the shipment of household goods, incidental expenses related to the moves, and home sale and home repurchase assistance. Also, as provided in Gulf Power's
relocation policy, tax assistance is provided on the taxable relocation benefits. If the named executive officer terminates within two years of relocation, these amounts must be repaid.
Personal Use of Corporate Aircraft. The Southern Company system has aircraft that are used to facilitate business travel. All flights on these aircraft must have a business purpose, except limited personal use that is associated with business travel is permitted for the President and Chief Executive Officer. Additionally, limited personal use related to relocation is permissible but must be approved. The amount reported for such personal use is the incremental cost of providing the benefit, primarily fuel costs. Also, if seating is available, Southern Company permits a spouse or other family member to accompany an employee on a flight. However, because in such cases the aircraft is being used for a business purpose, there is no incremental cost associated with the family travel, and no amounts are included for such travel. Any additional expenses incurred that are related to family travel are included.
In connection with Ms. Liu's relocation from Atlanta to Pensacola, Mr. Connally approved personal use of the corporate aircraft for one round-trip flight per month for six months. The perquisite amount shown for Ms. Liu includes $2,380 for this approved use of corporate aircraft. In connection with his relocation from Pensacola to Birmingham, Mr. Teel was approved for limited personal use of the corporate aircraft by the Chief Operating Officer of Southern Company. The perquisite amount shown for Mr. Teel includes $2,090 for this approved use of corporate aircraft.
Other Miscellaneous Perquisites. The amount included reflects the full cost to Gulf Power of providing the following items: personal use of company-provided tickets for sporting and other entertainment events and gifts distributed to and activities provided to attendees at company-sponsored events.
GRANTS OF PLAN-BASED AWARDS IN 2015
This table provides information on equity grants made and goals established for future payouts under the performance-based compensation programs during 2015 by the Compensation Committee. |
| | | | | | | | | | | | | | | |
Name (a) |
Grant Date (b) |
Estimated Future Payouts Under Non-Equity Incentive Plan Awards |
Estimated Future Payouts Under Equity Incentive Plan Awards |
Grant Date Fair Value of Stock and Option Awards ($) (i) |
Threshold ($) (c) | Target ($) (d) | Maximum ($) (e) | Threshold (#) (f) | Target (#) (g) | Maximum (#) (h) |
S. W. Connally, Jr. | | 2,557 |
| 255,671 |
| 511,343 |
| | | | |
| 2/9/2015 | | | | 117 |
| 11,761 |
| 23,522 |
| 553,946 |
|
X. Liu | | 1,231 |
| 123,125 |
| 246,250 |
| | | | |
| 2/9/2015 | | | | 32 |
| 3,288 |
| 6,576 |
| 154,865 |
|
R. S. Teel | | 1,234 |
| 123,402 |
| 246,804 |
| | | | |
| 2/9/2015 | | | | 33 |
| 3,327 |
| 6,654 |
| 156,703 |
|
J. R. Fletcher | | 1,082 |
| 108,211 |
| 216,423 |
| | | | |
| 2/9/2015 | | | | 30 |
| 3,064 |
| 6,128 |
| 144,315 |
|
W. E. Smith | | 818 |
| 81,822 |
| 163,644 |
| | | | |
| 2/9/2015 | | | | 17 |
| 1,737 |
| 3,474 |
| 81,813 |
|
B. C. Terry | | 1,261 |
| 126,119 |
| 252,237 |
| | | | |
| 2/9/2015 | | | | 35 |
| 3,571 |
| 7,142 |
| 168,195 |
|
Columns (c), (d), and (e)
These columns reflect the annual Performance Pay Program opportunity granted to the named executive officers in 2015 as described in the CD&A. The information shown as "Threshold," "Target," and "Maximum" reflects the range of potential payouts established by the Compensation Committee. The actual amounts earned are disclosed in the Summary Compensation Table. The amounts shown for Ms. Liu and Mr. Teel reflect the increases in salary and annual Performance Pay Program opportunity each received after their respective promotions in 2015.
Columns (f), (g), and (h)
These columns reflect the performance shares granted to the named executive officers in 2015 as described in the CD&A. The information shown as "Threshold," "Target," and "Maximum" reflects the range of potential payouts established by the Compensation Committee. Earned performance shares and accrued dividends will be paid out in Common Stock following the end of the 2015 through 2017 performance period, based on the extent to which the performance goals are achieved. Any shares not earned are forfeited.
Column (i)
This column reflects the aggregate grant date fair value of the performance shares granted in 2015. For performance shares, 50% of the value is based on the probable outcome of the performance conditions as of the grant date using a Monte Carlo simulation model ($46.43), while the other 50% is based on the closing price of the Common Stock on the grant date ($47.79). The assumptions used in calculating these amounts are discussed in Note 8 to the financial statements of Gulf Power in Item 8 herein.
OUTSTANDING EQUITY AWARDS AT 2015 FISCAL YEAR-END
This table provides information pertaining to all outstanding stock options and stock awards (performance shares) held by or granted to the named executive officers as of December 31, 2015.
|
| | | | | | | |
Name
(a)
| Option Awards | Stock Awards |
Name
(a)
| Number
of
Securities Underlying Unexercised Options
Exercisable
(#)
(b)
|
Number of Securities Underlying Unexercised Options
Unexercisable
(#)
(c)
|
Option Exercise Price
($)
(d)
|
Option Expiration Date
(e)
| Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested
(#)
(f)
| Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
($)
(g)
|
S. W. Connally, Jr. | 14,392
16,100
16,053
44,603
31,377
| 0
0
0
22,302
62,753
| 31.39
37.97
44.42
44.06
41.28
| 02/16/2019
02/14/2021
02/13/2022
02/11/2023
02/10/2024
| 8,274
12,354
| 387,140
578,044
|
X. Liu | 10,079
9,976
8,011
8,798
| 0
0
4,005
17,595
| 37.97
44.42
44.06
41.28
| 02/14/2021
02/13/2022
02/11/2023
02/10/2024
| 2,320
3,452
| 108,553
161,519
|
R. S. Teel | 9,078
9,332
9,629
16,774
16,926
13,493
9,219
| 0
0
0
0
0
6,747
18,436
| 35.78
31.39
31.17
37.97
44.42
44.06
41.28
| 02/18/2018
02/16/2019
02/15/2020
02/14/2021
02/13/2022
02/11/2023
02/10/2024
|
2,431
3,494
| 113,746
163,484
|
J. R.Fletcher | 3,376
9,371
7,456
5,122
| 0
0
3,728
10,242
| 37.97
44.42
44.06
41.28
| 02/14/2021
02/13/2022
02/11/2023
02/10/2024
| 1,350
3,218
| 63,167
150,570
|
W. E. Smith | 5,037
4,007
2,838
| 0
2,004
5,676
| 44.42
44.06
41.28
| 2/13/2022
2/11/2023
2/10/2024
| 748
1,823
| 34,999
85,298
|
B. C. Terry | 18,574
18,163
14,479
9,892
| 0
0
7,240
19,784
| 37.97
44.42
44.06
41.28
| 02/14/2021
02/13/2022
02/11/2023
02/10/2024
| 2,608
3,750
| 122,028
175,463
|
Columns (b), (c), (d), and (e)
Stock options vest one-third per year on the anniversary of the grant date. Options granted from 2007 through 2012 with expiration dates from 2017 through 2022 were fully vested as of December 31, 2015. The options granted in 2013 and 2014 become fully vested as shown below.
|
| | | | |
Year Option Granted | | Expiration Date | | Date Fully Vested |
2013 | | February 11, 2023 | | February 11, 2016 |
2014 | | February 10, 2024 | | February 10, 2017 |
Options also fully vest upon death, total disability, or retirement and expire three years following death or total disability or five years following retirement, or on the original expiration date if earlier. Please see Potential Payments upon Termination or Change in Control for more information about the treatment of stock options under different termination and change-in-control events.
Columns (f) and (g)
In accordance with SEC rules, column (f) reflects the target number of performance shares that can be earned at the end of each three-year performance period (December 31, 2016 and 2017) that were granted in 2014 and 2015, respectively. The number of shares reflected in column (f) for the performance shares granted in 2015 also reflects the deemed reinvestment of dividends on the target number of performance shares. The ultimate number of dividends a named executive will earn at the end of the performance period ultimately depends on Southern Company performance. If no performance shares are paid out, no dividends will be paid out.
The performance shares granted for the 2013 through 2015 performance period vested on December 31, 2015 and are shown in the Option Exercises and Stock Vested in 2015 table below. The value in column (g) is derived by multiplying the number of shares in column (f) by the Common Stock closing price on December 31, 2015 ($46.79). The ultimate number of shares earned, if any, will be based on the actual performance results at the end of each respective performance period. See further discussion of performance shares in the CD&A.See also Potential Payments upon Termination or Change in Control for more information about the treatment of performance shares under different termination and change-in-control events.
OPTION EXERCISES AND STOCK VESTED IN 2015
|
| | | | | | | | |
| Option Awards | Stock Awards |
Name (a) | Number of Shares Acquired on Exercise (#) (b) |
Value Realized on Exercise ($) (c) | Number of Shares Acquired on Vesting (#) (d) |
Value Realized on Vesting ($) (e) |
S. W. Connally, Jr. | 8,521 |
| 76,012 |
| 2,026 |
| 94,797 |
|
X. Liu | — |
| — |
| 364 |
| 17,032 |
|
R. S. Teel | — |
| — |
| 613 |
| 28,682 |
|
J. R. Fletcher | — |
| — |
| 339 |
| 15,862 |
|
W. E. Smith | — |
| — |
| 182 |
| 8,516 |
|
B. C. Terry | 12,918 |
| 159,464 |
| 657 |
| 30,741 |
|
Columns (b) and (c)
Column (b) reflects the number of shares acquired upon the exercise of stock options during 2015 and column (c) reflects the value realized. The value realized is the difference in the market price over the exercise price on the exercise date.
Columns (d) and (e)
Column (d) includes the performance shares awarded for the 2013 through 2015 performance period that vested on December 31, 2015. The value reflected in column (e) is derived by multiplying the number of shares in column (d) by the market value of the underlying shares on the vesting date ($46.79).
PENSION BENEFITS AT 2015 FISCAL YEAR-END
|
| | | | |
Name | Plan Name | Number of Years Credited Service (#) | Present Value of Accumulated Benefit ($) | Payments During
Last Fiscal Year ($)
|
(a) | (b) | (c) | (d) | (e) |
S.W. Connally, Jr. | Pension Plan
SBP-P
SERP
| 24.17
24.17
24.17
| 564,283
600,176
396,421
| 0
0
0
|
X. Liu | Pension Plan
SBP-P
SERP
| 15.92
15.92
15.92
| 364,469
76,721
130,872
| 0
0
0
|
R. S. Teel | Pension Plan
SBP-P
SERP
| 15.33
15.33
15.33
| 343,793
65,959
113,213
| 0
0
0
|
J. R. Fletcher | Pension Plan
SBP-P
SERP
| 25.58
25.58
25.58
| 590,440
127,297
194,480
| 0
0
0
|
W. E. Smith | Pension Plan
SBP-P
SERP
| 28.17
28.17
28.17
| 619,105
57,930
165,857
| 0
0
0
|
B. C. Terry | Pension Plan
SBP-P
SERP
SRA
| 13.50
13.50
13.50
10.00
| 324,159
75,303
103,371
406,099
| 0
0
0
0
|
Pension Plan
The Pension Plan is a tax-qualified, funded plan. It is Southern Company's primary retirement plan. Substantially all employees participate in this plan after one year of service. Normal retirement benefits become payable when participants attain age 65 and complete five years of participation. The plan benefit equals the greater of amounts computed using a "1.7% offset formula" and a "1.25% formula," as described below. Benefits are limited to a statutory maximum.
The 1.7% offset formula amount equals 1.7% of final average pay times years of participation less an offset related to Social Security benefits. The offset equals a service ratio times 50% of the anticipated Social Security benefits in excess of $4,200. The service ratio adjusts the offset for the portion of a full career that a participant has worked. The highest three rates of pay out of a participant's last 10 calendar years of service are averaged to derive final average pay. The rates of pay considered for this formula are the base salary rates with no adjustments for voluntary deferrals after 2008. A statutory limit restricts the amount considered each year; the limit for 2015 was $265,000.
The 1.25% formula amount equals 1.25% of final average pay times years of participation. For this formula, the final average pay computation is the same as above, but annual performance-based compensation earned each year is added to the base salary rates of pay.
Early retirement benefits become payable once plan participants have, during employment, attained age 50 and completed 10 years of participation. Participants who retire early from active service receive benefits equal to the amounts computed using the same formulas employed at normal retirement. However, a 0.3% reduction applies for each month (3.6% for each year) prior to normal retirement that participants elect to have their benefit payments commence. For example, 64% of the formula benefits are payable starting at age 55. As of December 31, 2015, Mses. Liu and Terry and Messrs. Connally, Fletcher, and Teel were not retirement-eligible.
The Pension Plan's benefit formulas produce amounts payable monthly over a participant's post-retirement lifetime. At retirement, plan participants can choose to receive their benefits in one of seven alternative forms of payment. All forms pay benefits monthly over the lifetime of the retiree or the joint lifetimes of the retiree and a spouse. A reduction applies if a retiring participant chooses a payment form other than a single life annuity. The reduction makes the value of the benefits paid in the form chosen comparable to what it would have been if benefits were paid as a single life annuity over the retiree's life.
Participants vest in the Pension Plan after completing five years of service. As of December 31, 2015, all of the named executive officers are vested in their Pension Plan benefits. Participants who terminate employment after vesting can elect to have their pension
benefits commence at age 50 if they participated in the Pension Plan for 10 years. If such an election is made, the early retirement reductions that apply are actuarially determined factors and are larger than 0.3% per month.
If a participant dies while actively employed and is either age 50 or vested in the Pension Plan as of date of death, benefits will be paid to a surviving spouse. A survivor's benefit equals 45% of the monthly benefit that the participant had earned before his or her death. Payments to a surviving spouse of a participant who could have retired will begin immediately. Payments to a survivor of a participant who was not retirement-eligible will begin when the deceased participant would have attained age 50.
After commencing, survivor benefits are payable monthly for the remainder of a survivor's life. Participants who are eligible for early retirement may opt to have an 80% survivor benefit paid if they die; however, there is a charge associated with this election.
If participants become totally disabled, periods that Social Security or employer-provided disability income benefits are paid will count as service for benefit calculation purposes. The crediting of this additional service ceases at the point a disabled participant elects to commence retirement payments. Outside of this extra service crediting, the normal Pension Plan provisions apply to disabled participants.
The Southern Company Supplemental Benefit Plan (Pension-Related) (SBP-P)
The SBP-P is an unfunded retirement plan that is not tax qualified. This plan provides high-paid employees any benefits that the Pension Plan cannot pay due to statutory pay/benefit limits. The SBP-P's vesting and early retirement provisions mirror those of the Pension Plan. Its disability provisions mirror those of the Pension Plan but cease upon a participant's separation from service.
The amounts paid by the SBP-P are based on the additional monthly benefit that the Pension Plan would pay if the statutory limits and pay deferrals were ignored. When a SBP-P participant separates from service, vested monthly benefits provided by the benefit formulas are converted into a single sum value. It equals the present value of what would have been paid monthly for an actuarially determined average post-retirement lifetime. The discount rate used in the calculation is based on the 30-year U.S. Treasury yields for the September preceding the calendar year of separation, but not more than six percent.
Vested participants terminating prior to becoming eligible to retire will be paid their single sum value as of September 1 following the calendar year of separation. If the terminating participant is retirement-eligible, the single sum value will be paid in 10 annual installments starting shortly after separation. The unpaid balance of a retiree's single sum will be credited with interest at the prime rate published in The Wall Street Journal. If the separating participant is a "key man" under Section 409A of the Internal Revenue Code, the first installment will be delayed for six months after the date of separation.
If a SBP-P participant dies after becoming vested in the Pension Plan, the spouse of the deceased participant will receive the installments the participant would have been paid upon retirement. If a vested participant's death occurs prior to age 50, the installments will be paid to a spouse as if the participant had survived to age 50.
The Southern Company Supplemental Executive Retirement Plan (SERP)
The SERP is also an unfunded retirement plan that is not tax qualified. This plan provides high-paid employees additional benefits that the Pension Plan and the SBP-P would pay if the 1.7% offset formula calculations reflected a portion of annual performance-based compensation. To derive the SERP benefits, a final average pay is determined reflecting participants' base rates of pay and their annual performance-based compensation amounts, whether or not deferred, to the extent they exceed 15% of those base rates (ignoring statutory limits). This final average pay is used in the 1.7% offset formula to derive a gross benefit. The Pension Plan and the SBP-P benefits are subtracted from the gross benefit to calculate the SERP benefit. The SERP's early retirement, survivor benefit, disability, and form of payment provisions mirror the SBP-P's provisions. However, except upon a change in control, SERP benefits do not vest until participants retire, so no benefits are paid if a participant terminates prior to becoming retirement-eligible. More information about vesting and payment of SERP benefits following a change in control is included under Potential Payments upon Termination or Change-in-Control.
Supplemental Retirement Agreements (SRA)
Gulf Power also provides supplemental retirement benefits to certain employees that were first employed by Gulf Power, or an affiliate of Gulf Power, in the middle of their careers and generally provide for additional retirement benefits by giving credit for years of employment prior to employment with Gulf Power or one of its affiliates. These supplemental retirement benefits are also unfunded and not tax-qualified. Information about the SRA with Ms. Terry is included in the CD&A.
Pension Benefit Assumptions
The following assumptions were used in the present value calculations for all pension benefits:
|
| | | | | |
l | | Discount rate - 4.70% Pension Plan and 4.14% supplemental plans as of December 31, 2015, |
l | | Retirement date - Normal retirement age (65 for all named executive officers), |
l | | Mortality after normal retirement - Adjusted RP-2014 with generational projections, |
l | | Mortality, withdrawal, disability, and retirement rates prior to normal retirement - None, |
l | | Form of payment for Pension Benefits: |
| o | | Male retirees: 25% single life annuity; 25% level income annuity; 25% joint and 50% survivor annuity; and 25% joint and 100% survivor annuity, |
| o | | Female retirees: 50% single life annuity; 30% level income annuity; 15% joint and 50% survivor annuity; and 5% joint and 100% survivor annuity, |
l | | Spouse ages - Wives two years younger than their husbands, |
l | | Annual performance-based compensation earned but unpaid as of the measurement date - 130% of target opportunity percentages times base rate of pay for year amount is earned, and |
l | | Installment determination - 3.75% discount rate for single sum calculation and 4.25% prime rate during installment payment period. |
For all of the named executive officers, the number of years of credited service for the Pension Plan, the SBP-P, and the SERP is one year less than the number of years of employment.
NONQUALIFIED DEFERRED COMPENSATION AS OF 2015 FISCAL YEAR-END
|
| | | | | | | | |
Name (a) |
Executive Contributions in Last FY ($) (b) |
Registrant Contributions in Last FY ($) (c) |
Aggregate Earnings in Last FY ($) (d) |
Aggregate Withdrawals/ Distributions ($) (e) |
Aggregate Balance at Last FYE ($) (f) |
S. W. Connally, Jr. | — | 7,943 |
| 8,125 |
| — | 143,905 |
|
X. Liu | — | 19 |
| 4,274 |
| — | 133,018 |
|
R. S. Teel | — | 101 |
| 1 | — | 264 |
|
J. R. Fletcher | — | — |
| — |
| — | — |
|
W. E. Smith | 49,139 | 1,563 |
| 2,846 |
| — | 101,063 |
|
B. C. Terry | 86,917 | 698 |
| 7,771 |
| — | 365,783 |
|
Southern Company provides the DCP, which is designed to permit participants to defer income as well as certain federal, state, and local taxes until a specified date or their retirement or other separation from service. Up to 50% of base salary and up to 100% of performance-based non-equity compensation may be deferred at the election of eligible employees. All of the named executive officers are eligible to participate in the DCP.
Participants have two options for the deemed investments of the amounts deferred - the Stock Equivalent Account and the Prime Equivalent Account. Under the terms of the DCP, participants are permitted to transfer between investments at any time.
The amounts deferred in the Stock Equivalent Account are treated as if invested at an equivalent rate of return to that of an actual investment in Common Stock, including the crediting of dividend equivalents as such are paid by Southern Company from time to time. It provides participants with an equivalent opportunity for the capital appreciation (or loss) and income of that of a Southern Company stockholder. During 2015, the rate of return in the Stock Equivalent Account was -0.01%.
Alternatively, participants may elect to have their deferred compensation deemed invested in the Prime Equivalent Account which is treated as if invested at a prime interest rate compounded monthly, as published in The Wall Street Journal as the base rate on corporate loans posted as of the last business day of each month by at least 75% of the United States' largest banks. The interest rate earned on amounts deferred during 2015 in the Prime Equivalent Account was 3.32%.
Column (b)
This column reports the actual amounts of compensation deferred under the DCP by each named executive officer in 2015. The amount of salary deferred by the named executive officers, if any, is included in the Salary column in the Summary Compensation Table. The amounts of performance-based compensation deferred in 2015 were the amounts that were earned as of December 31, 2014 but not payable until the first quarter of 2015. These amounts are not reflected in the Summary Compensation Table because that table reports performance-based compensation that was earned in 2015, but not payable until early 2016. These deferred amounts may be distributed in a lump sum or in up to 10 annual installments at termination of employment or in a lump sum at a specified date, at the election of the participant.
Column (c)
This column reflects contributions under the SBP. Under the Internal Revenue Code, employer-matching contributions are prohibited under the ESP on employee contributions above stated limits in the ESP, and, if applicable, above legal limits set forth in the Internal Revenue Code. The SBP is a nonqualified deferred compensation plan under which contributions are made that are prohibited from being made in the ESP. The contributions are treated as if invested in Common Stock and are payable in cash upon termination of employment in a lump sum or in up to 20 annual installments, at the election of the participant. The amounts reported in this column also were reported in the All Other Compensation column in the Summary Compensation Table.
Column (d)
This column reports earnings or losses on both compensation the named executive officers elected to defer and on employer contributions under the SBP.
Column (f)
This column includes amounts that were deferred under the DCP and contributions under the SBP in prior years and reported in Gulf Power's prior years' Information Statements or Annual Reports on Form 10-K. The following chart shows the amounts reported in Gulf Power's prior years' Information Statements or Annual Reports on Form 10-K.
|
| | | | | | | | | | | | | | | |
| | Amounts Deferred under the DCP Prior to 2015 and Reported in Prior Years' Information Statements or Annual Reports on Form 10-K | | Employer Contributions under the SBP Prior to 2015 and Reported in Prior Years' Information Statements or Annual Reports on Form 10-K | | | Total | |
Name | | | ($) | | | | ($) | | | | ($) | |
S. W. Connally, Jr. | | | 31,742 |
| | | | 18,887 |
| | | | 50,629 |
| |
X. Liu | | | — |
| | | | — |
| | | | — |
| |
R. S. Teel | | | — |
| | | | — |
| | | | — |
| |
J. R. Fletcher | | | — |
| | | | — |
| | | | — |
| |
W. E. Smith | | | — |
| | | | — |
| | | | — |
| |
B. C. Terry | | | 287,157 |
| | | | 1,488 |
| | | | 288,645 |
| |
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
This section describes and estimates payments that could be made to the named executive officers serving as of December 31, 2015 under different termination and change-in-control events. The estimated payments would be made under the terms of Southern Company's compensation and benefit program or the change-in-control severance program. All of the named executive officers are participants in Southern Company's change-in-control severance program for officers. The amount of potential payments is calculated as if the triggering events occurred as of December 31, 2015 and assumes that the price of Common Stock is the closing market price on December 31, 2015.
Description of Termination and Change-in-Control Events
The following charts list different types of termination and change-in-control events that can affect the treatment of payments under the compensation and benefit programs. No payments are made under the change-in-control severance program unless, within two years of the change in control, the named executive officer is involuntarily terminated or voluntarily terminates for Good Reason. (See the description of Good Reason below.)
Traditional Termination Events
|
| | |
l | | Retirement or Retirement-Eligible - Termination of a named executive officer who is at least 50 years old and has at least 10 years of credited service. |
l | | Resignation - Voluntary termination of a named executive officer who is not retirement-eligible. |
l | | Lay Off - Involuntary termination of a named executive officer who is not retirement-eligible not for cause. |
l | | Involuntary Termination - Involuntary termination of a named executive officer for cause. Cause includes individual performance below minimum performance standards and misconduct, such as violation of Gulf Power's Drug and Alcohol Policy. |
l | | Death or Disability - Termination of a named executive officer due to death or disability. |
Change-in-Control-Related Events
At the Southern Company or Gulf Power level:
|
| | |
l | | Southern Company Change-in-Control I - Consummation of an acquisition by another entity of 20% or more of Common Stock, or following consummation of a merger with another entity, Southern Company's stockholders own 65% or less of the entity surviving the merger. |
l | | Southern Company Change-in-Control II - Consummation of an acquisition by another entity of 35% or more of Common Stock, or following consummation of a merger with another entity, Southern Company shareholders own less than 50% of Southern Company surviving the merger. |
l | | Southern Company Does Not Survive Merger - Consummation of a merger or other event and Southern Company is not the surviving company or the Common Stock is no longer publicly traded. |
l | | Gulf Power Change in Control - Consummation of an acquisition by another entity, other than another subsidiary of Southern Company, of 50% or more of the stock of Gulf Power, consummation of a merger with another entity and Gulf Power is not the surviving company, or the sale of substantially all the assets of Gulf Power. |
At the employee level:
|
| | |
l | | Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason - Employment is terminated within two years of a change in control, other than for cause, or the employee voluntarily terminates for Good Reason. Good Reason for voluntary termination within two years of a change in control generally is satisfied when there is a material reduction in salary, performance-based compensation opportunity, or benefits; relocation of over 50 miles; or a diminution in duties and responsibilities. |
The following chart describes the treatment of different pay and benefit elements in connection with the Traditional Termination Events as described above.
|
| | | | | |
Program |
Retirement/
Retirement-
Eligible
| Lay Off
(Involuntary
Termination
Not For Cause)
| Resignation |
Death or
Disability
|
Involuntary
Termination
(For Cause)
|
Pension Benefits Plans | Benefits payable
as described in the notes following
the Pension
Benefits table.
| Same as Retirement. | Same as Retirement. | Same as Retirement. | Same as Retirement. |
Annual Performance Pay Program | Prorated if
retire before 12/31.
| Same as Retirement. | Forfeit. | Same as Retirement. | Forfeit. |
Stock Options | Vest; expire earlier of original expiration date or five years. | Vested options expire in 90 days; unvested are forfeited. | Same as Lay Off. | Vest; expire earlier of original expiration date or three years. | Forfeit. |
Performance Shares | No proration if retirement prior to end of performance period. Will receive full amount actually earned. | Forfeit. | Forfeit. | Death - prorate for amount of time employed during performance period.
Disability - not affected.
| Forfeit. |
Financial
Planning Perquisite
| Continues for one year. | Terminates. | Terminates. | Same as Retirement. | Terminates. |
DCP | Payable per prior elections (lump
sum or up to 10 annual installments).
| Same as Retirement. | Same as Retirement. | Payable to beneficiary or participant per prior elections. Amounts deferred prior to 2005 can be paid as a lump sum per the benefit administration committee's discretion. | Same as Retirement. |
SBP - non-pension related | Payable per prior elections (lump
sum or up to 20 annual installments).
| Same as Retirement. | Same as Retirement. | Same as the DCP. | Same as Retirement. |
The following chart describes the treatment of payments under compensation and benefit programs under different change-in-control events, except the Pension Plan. The Pension Plan is not affected by change-in-control events. |
| | | | |
Program |
Southern Company
Change-in-Control I
|
Southern Company
Change-in-Control II
|
Southern Company
Does Not Survive Merger or Gulf Power Change in
Control
| Involuntary
Change-in-
Control-Related
Termination or
Voluntary
Change-in-
Control-Related
Termination
for Good Reason
|
Nonqualified Pension Benefits
(except SRA)
| All SERP-related benefits vest if participants vested in tax-qualified pension benefits; otherwise, no impact. SBP - pension- related benefits vest for all participants and single sum value of benefits earned to change-in-control date paid following termination or retirement. | Benefits vest for all participants and single sum value of benefits earned to the change-in-control date paid following termination or retirement. | Same as Southern Company Change-
in-Control II.
| Based on type of change-in-control event. |
SRA | Not affected. | Not affected. | Not affected. | Vest. |
Annual Performance Pay Program | If no program
termination, paid at greater of target or actual performance. If program terminated within two years of change in control, prorated at target performance level.
| Same as Southern Company Change-in-Control I. | Prorated at target performance level. | If not otherwise eligible for payment, if the program is still in effect, prorated at target performance level. |
Stock Options | Not affected. | Not affected. | Vest and convert to surviving company's securities; if cannot convert, pay spread in cash. | Vest. |
Performance Shares | Not affected. | Not affected. | Vest and convert to surviving company's securities; if cannot convert, pay spread in cash. | Vest. |
DCP | Not affected. | Not affected. | Not affected. | Not affected. |
SBP | Not affected. | Not affected. | Not affected. | Not affected. |
Severance Benefits | Not applicable. | Not applicable. | Not applicable. | One or two times base salary plus target annual performance-based pay. |
Healthcare Benefits | Not applicable. | Not applicable. | Not applicable. | Up to five years participation in group healthcare plan plus payment of two or three years' premium amounts. |
Outplacement Services | Not applicable. | Not applicable. | Not applicable. | Six months. |
Potential Payments
This section describes and estimates payments that would become payable to the named executive officers upon a termination or change in control as of December 31, 2015.
Pension Benefits
The amounts that would have become payable to the named executive officers if the Traditional Termination Events occurred as of December 31, 2015 under the Pension Plan, the SBP-P, the SERP, and, if applicable, an SRA are itemized in the following chart. The amounts shown under the Retirement column are amounts that would have become payable to the named executive officers that were retirement-eligible on December 31, 2015 and are the monthly Pension Plan benefits and the first of 10 annual installments from the SBP-P and the SERP. The amounts shown under the Resignation or Involuntary Termination column are the amounts that would have become payable to the named executive officers who were not retirement-eligible on December 31, 2015 and are the monthly Pension Plan benefits that would become payable as of the earliest possible date under the Pension Plan and the single sum value of benefits earned up to the termination date under the SBP-P, paid as a single payment rather than in 10 annual installments. Benefits under the SERP would be forfeited. The amounts shown that are payable to a spouse in the event of the death of the named executive officer are the monthly amounts payable to a spouse under the Pension Plan and the first of 10 annual installments from the SBP-P and the SERP.
The amounts in this chart are very different from the pension values shown in the Summary Compensation Table and the Pension Benefits table. Those tables show the present values of all the benefit amounts anticipated to be paid over the lifetimes of the named executive officers and their spouses. Those plans are described in the notes following the Pension Benefits table. Of the named executive officers, Mses. Liu and Terry and Messrs. Connally, Fletcher, and Teel were not retirement-eligible on December 31, 2015. The SRA for Ms. Terry contains an additional service requirement for benefit eligibility which was not met as of December 31, 2015. Therefore she was not eligible to receive retirement benefits under the agreement. However, death benefits would be paid to her surviving spouse.
|
| | | | | | | | | | | | | |
Name | Retirement ($) | Resignation or Involuntary Termination ($) | Death (payments to a spouse) ($) | |
S. W. Connally, Jr. | Pension | n/a | 2,318 | | 3,807 |
| |
| SBP-P | n/a | 750,455 | | 86,598 |
| |
| SERP | n/a | — | | 57,199 |
| |
X. Liu | Pension | n/a | 1,441 | | 2,367 |
| |
| SBP-P | n/a | 96,134 | | 11,183 |
| |
| SERP | n/a | — | | 19,076 |
| |
R. S. Teel | Pension | n/a | 1,437 | | 2,360 |
| |
| SBP-P | n/a | 82,766 | | 9,679 |
| |
| SERP | n/a | — | | 16,614 |
| |
J. R. Fletcher | Pension | n/a | 2,093 | | 3,438 |
| |
| SBP-P | n/a | 154,733 | | 16,044 |
| |
| SERP | n/a | — | | 24,512 |
| |
W. E. Smith | Pension | 3,700 | All plans treated as retiring | | 3,398 |
| |
| SBP-P | 7,305 | | 7,305 |
| |
| SERP | 20,914 | | 20,914 |
| |
B. C. Terry | Pension | n/a | 1,296 | | 2,129 |
| |
| SBP-P | n/a | 94,266 | | 11,088 |
| |
| SERP | n/a | — | | 15,221 |
| |
| SRA | n/a | — | | 59,796 |
| |
As described in the Change-in-Control chart, the only change in the form of payment, acceleration, or enhancement of the pension benefits is that the single sum value of benefits earned up to the change-in-control date under the SBP-P, the SERP, and the SRA could be paid as a single payment rather than in 10 annual installments. Also, the SERP benefits vest for participants who are not
retirement-eligible upon a change in control. Estimates of the single sum payment that would have been made to the named executive officers, assuming termination as of December 31, 2015 following a change-in-control-related event, other than a Southern Company Change-in-Control I (which does not impact how pension benefits are paid), are itemized below. These amounts would be paid instead of the benefits shown in the Traditional Termination Events chart above; they are not paid in addition to those amounts.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Name | | SBP-P ($) | | SERP ($) | SRA ($) | Total ($) | | |
S. W. Connally, Jr. | | | 736,542 | | | | | 486,491 | | | — | | | 1,223,033 | | |
X. Liu | | | 94,352 | | | | | 160,949 | | | — | | | 255,301 | | |
R. S. Teel | | | 81,232 | | | | | 139,429 | | | — | | | 220,661 | | |
J. R. Fletcher | | | 151,864 | | | | | 232,012 | | | — | | | 383,876 | | |
W. E. Smith | | | 73,047 | | | | | 209,141 | | | — | | | 282,188 | | |
B. C. Terry | | | 92,519 | | | | | 127,003 | | | 498,939 | | | 718,461 | | |
The pension benefit amounts in the tables above were calculated as of December 31, 2015 assuming payments would begin as soon as possible under the terms of the plans. Accordingly, appropriate early retirement reductions were applied. Any unpaid annual performance-based compensation was assumed to be paid at 1.30 times the target level. Pension Plan benefits were calculated assuming each named executive officer chose a single life annuity form of payment, because that results in the greatest monthly benefit. The single sum values were based on a 3.26 % discount rate.
Annual Performance Pay Program
The amount payable if a change in control had occurred on December 31, 2015 is the greater of target or actual performance. Because actual payouts for 2015 performance were above the target level for all of the named executive officers, the amount that would have been payable to the named executive officers was the actual amount paid as reported in the CD&A and the Summary Compensation Table.
Stock Optionsand Performance Shares (Equity Awards)
Equity Awards would be treated as described in the Termination and Change-in-Control charts above. If Southern Company consummates a merger and is not the surviving company, all Equity Awards vest. However, there is no payment associated with Equity Awards in that situation unless the participants' Equity Awards cannot be converted into surviving company awards. In that event, the value of outstanding Equity Awards would be paid to the named executive officers. In addition, if there is an Involuntary Change-in-Control Termination or Voluntary Change-in-Control Termination for Good Reason, Equity Awards vest.
For stock options, the value is the excess of the exercise price and the closing price of Common Stock on December 31, 2015. The value of performance shares is calculated using the closing price of Common Stock on December 31, 2015.
The chart below shows the number of stock options for which vesting would be accelerated under a Southern Company Termination and the amount that would be payable under a Southern Company Termination if there were no conversion to the surviving company's stock options. It also shows the number and value of performance shares that would be paid.
|
| | | | | | | | | | | | |
| | Total Number of | |
| Number of Equity | Equity Awards | Total Payable in |
| Awards with | Following | Cash without |
| Accelerated Vesting (#) | Accelerated Vesting (#) | Conversion of |
| Stock | Performance | | Stock | Performance | | Equity |
Name | Options | Shares | | Options | Shares | | Awards ($) |
S. W. Connally, Jr. | 85,055 |
| 20,628 |
| | 207,580 |
| 20,628 |
| | 2,068,175 |
|
X. Liu | 21,600 |
| 5,772 |
| | 58,464 |
| 5,772 |
| | 560,841 |
|
R. S. Teel | 25,183 |
| 5,925 |
| | 109,634 |
| 5,925 |
| | 1,066,993 |
|
J. R. Fletcher | 13,970 |
| 4,568 |
| | 39,295 |
| 4,568 |
| | 380,910 |
|
W. E. Smith | 7,680 |
| 2,571 |
| | 19,562 |
| 2,571 |
| | 195,557 |
|
B. C. Terry | 27,024 |
| 6,358 |
| | 88,132 |
| 6,358 |
| | 727,167 |
|
DCP and SBP
The aggregate balances reported in the Nonqualified Deferred Compensation table would be payable to the named executive officers as described in the Traditional Termination and Change-in-Control-Related Events charts above. There is no enhancement or acceleration of payments under these plans associated with termination or change-in-control events, other than the lump-sum payment opportunity described in the above charts. The lump sums that would be payable are those that are reported in the Nonqualified Deferred Compensation table.
Healthcare Benefits
Mr. Smith is retirement-eligible. Healthcare benefits are provided to retirees, and there is no incremental payment associated with the termination or change-in-control events. Because the other named executive officers were not retirement-eligible at the end of 2015, healthcare benefits would not become available until each reaches age 50, except in the case of a change-in-control-related termination, as described in the Change-in-Control-Related Events chart. The estimated cost of providing healthcare insurance premiums for up to a maximum of two years for Mses. Liu and Terry and Messrs. Fletcher and Teel is $17,482, $10,613, $27,597, and $27,597, respectively. The estimated cost of providing healthcare insurance premiums for up to a maximum of three years for Mr. Connally is $42,966.
Financial Planning Perquisite
An additional year of the financial planning perquisite, which is set at a maximum of $8,700 per year, will be provided after retirement for retirement-eligible named executive officers.
There are no other perquisites provided to the named executive officers under any of the traditional termination or change-in-control-related events.
Severance Benefits
The named executive officers are participants in a change-in-control severance plan. The plan provides severance benefits, including outplacement services, if within two years of a change in control, they are involuntarily terminated, not for cause, or they voluntarily terminate for Good Reason. The severance benefits are not paid unless the named executive officer releases the employing company from any claims he or she may have against the employing company.
The estimated cost of providing the six months of outplacement services is $6,000 per named executive officer. The severance payment is two times the base salary and target payout under the annual Performance Pay Program for Mr. Connally and one times the base salary and target payout under the annual Performance Pay Program for the other named executive officers. If any portion of the severance amount constitutes an "excess parachute payment" under Section 280G of the Internal Revenue Code and is therefore subject to an excise tax, the severance amount will be reduced unless the after-tax "unreduced amount" exceeds the after-tax "reduced amount." Excise tax gross-ups will not be provided on change-in-control severance payments.
The table below estimates the severance payments that would be made to the named executive officers if they were terminated as of December 31, 2015 in connection with a change in control.
|
| | | | |
| | | |
Name | Severance Amount ($) |
S. W. Connally, Jr. | 1,363,581 | |
X. Liu | 396,736 | |
R. S. Teel | 397,629 | |
J. R. Fletcher | 348,681 | |
W. E. Smith | 286,378 | |
B. C. Terry | 406,382 | |
DIRECTOR COMPENSATION
Only non-employee directors of Gulf Power are compensated for service on the board of directors.
During 2015, the pay components for non-employee directors were:
|
| |
Annual cash retainer: | $22,000 per year |
Annual stock retainer: | $19,500 per year in Common Stock |
Board meeting fees: | If more than five meetings are held in a calendar year, $1,200 will be paid for participation beginning with the sixth meeting. |
Committee meeting fees: | If more than five meetings of any one committee are held in a calendar year, $1,000 will be paid for participation in each meeting of that committee beginning with the sixth meeting. |
DIRECTOR DEFERRED COMPENSATION PLAN
Any deferred quarterly equity grants or stock retainers are required to be deferred in the Deferred Compensation Plan For Directors of Gulf Power Company (Director Deferred Compensation Plan) and are invested in Common Stock units which earn dividends as if invested in Common Stock. Earnings are reinvested in additional stock units. Upon leaving the board, distributions are made in shares of Common Stock or cash.
In addition, directors may elect to defer up to 100% of their remaining compensation in the Director Deferred Compensation Plan until membership on the board ends. Deferred compensation may be invested as follows, at the director's election:
in Common Stock units which earn dividends as if invested in Common Stock and are distributed in shares of Common Stock or cash upon leaving the board;
at prime interest which is paid in cash upon leaving the board.
All investments and earnings in the Director Deferred Compensation Plan are fully vested and, at the election of the director, may be distributed in a lump sum payment or in up to 10 annual distributions after leaving the board.
DIRECTOR COMPENSATION TABLE
The following table reports all compensation to Gulf Power's non-employee directors during 2015, including amounts deferred in the Director Deferred Compensation Plan. Non-employee directors do not receive Non-Equity Incentive Plan Compensation or stock option awards, and there is no pension plan for non-employee directors.
|
| | | | | | | | | |
Name | Fees Earned or Paid in Cash ($)(1) | Stock Awards ($)(2) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) | All Other Compensation ($)(3) | Total ($) |
Allan G. Bense | 22,000 |
| 19,500 |
| 0 | 415 |
| 41,915 |
|
Deborah H. Calder | 22,000 |
| 19,500 |
| 0 | 342 |
| 41,842 |
|
William C. Cramer, Jr. | 22,000 |
| 19,500 |
| 0 | 379 |
| 41,879 |
|
Julian B. MacQueen | 22,000 |
| 19,500 |
| 0 | 391 |
| 41,891 |
|
J. Mort O'Sullivan III | 22,000 |
| 19,500 |
| 0 | 391 |
| 41,891 |
|
Michael T. Rehwinkel | 22,000 |
| 19,500 |
| 0 | 391 |
| 41,891 |
|
Winston E. Scott | 22,000 |
| 19,500 |
| 0 | 391 |
| 41,891 |
|
| |
(1) | Includes amounts voluntarily deferred in the Director Deferred Compensation Plan. |
| |
(2) | Includes fair market value of equity grants on grant dates. All such stock awards are vested immediately upon grant. |
| |
(3) | Consists of reimbursement for taxes on imputed income associated with gifts and activities provided to attendees at Southern Company system-sponsored events. |
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee is made up of non-employee directors of Southern Company who have never served as executive officers of Southern Company or Gulf Power. During 2015, none of Southern Company's or Gulf Power's executive officers served on the board of directors of any entities whose directors or executive officers serve on the Compensation Committee.
|
| |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Security Ownership (Applicable to Gulf Power only).
Security Ownership of Certain Beneficial Owners. Southern Company is the beneficial owner of 100% of the outstanding common stock of Gulf Power. The number of outstanding shares reported in the table below is as of January 31, 2016.
|
| | | | | | | | |
Title of Class | | Name and Address
of Beneficial
Owner
| | Amount and
Nature of
Beneficial
Ownership
| | Percent
of
Class
|
Common Stock | | The Southern Company
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
| | | | 100 | % |
| | Registrant:
Gulf Power
| | 5,642,717 |
| | |
Security Ownership of Management. The following tables show the number of shares of Common Stock owned by the directors, nominees, and executive officers as of December 31, 2015. It is based on information furnished by the directors, nominees, and executive officers. The shares beneficially owned by all directors, nominees, and executive officers as a group constitute less than one percent of the total number of shares of Common Stock outstanding on December 31, 2015.
|
| | | | | | | | | | |
| | | Shares Beneficially Owned Include: |
Name of Directors, Nominees, and Executive Officers | Shares Beneficially Owned (1) | | Deferred Stock Units (2) | | Shares Individuals Have Rights to Acquire Within 60 Days (3) | Shares Held By Family Member (4) |
S. W. Connally, Jr. | 188,536 |
| | 0 |
| | 176,204 |
| 0 |
|
Allan G. Bense | 4,457 |
| | 0 |
| | 0 |
| 0 |
|
Deborah H. Calder | 2,627 |
| | 2,098 |
| | 0 |
| 0 |
|
William C. Cramer, Jr. | 19,293 |
| | 18,278 |
| | 0 |
| 0 |
|
Julian B. MacQueen | 1,453 |
| | 0 |
| | 0 |
| 0 |
|
J. Mort O'Sullivan III | 3,877 |
| | 3,877 |
| | 0 |
| 0 |
|
Michael T. Rehwinkel | 946 |
| | 0 |
| | 0 |
| 0 |
|
Winston E. Scott | 6,115 |
| | 0 |
| | 0 |
| 0 |
|
Jim R. Fletcher | 37,280 |
| | 0 |
| | 34,174 |
| 0 |
|
Xia Liu | 52,157 |
| | 0 |
| | 49,667 |
| 0 |
|
Wendell E. Smith | 21,816 |
| | 0 |
| | 16,724 |
| 0 |
|
Richard S. Teel | 102,122 |
| | 0 |
| | 100,416 |
| 2,973 |
|
Bentina C. Terry | 86,854 |
| | 0 |
| | 78,240 |
| 0 |
|
Directors, Nominees, and Executive Officers as a group (14 people) | 632,110 |
| | 24,253 |
| | 499,101 |
| 2,973 |
|
| |
(1) | "Beneficial ownership" means the sole or shared power to vote, or to direct the voting of, a security and/or investment power with respect to a security or any combination thereof. |
| |
(2) | Indicates the number of deferred stock units held under the Director Deferred Compensation Plan. |
| |
(3) | Indicates shares of Common Stock that certain executive officers have the right to acquire within 60 days. Shares indicated are included in the Shares Beneficially Owned column. |
| |
(4) | Shares indicated are included in the Shares Beneficially Owned column. |
Changes in Control. Southern Company and Gulf Power know of no arrangements which may at a subsequent date result in any change in control.
|
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. |
Transactions with Related Persons.
In 2015, Mr. Antonio Terry, the spouse of Ms. Bentina Terry, an executive officer of Gulf Power, was employed by Gulf Power as a Senior Engineer and received compensation of $120,670.
Review, Approval or Ratification of Transactions with Related Persons.
Gulf Power does not have a written policy pertaining solely to the approval or ratification of "related party transactions." Southern Company has a Code of Ethics as well as a Contract Guidance Manual and other formal written procurement policies and procedures that guide the purchase of goods and services, including requiring competitive bids for most transactions above $10,000 or approval based on documented business needs for sole sourcing arrangements. The approval and ratification of any related party transactions would be subject to these written policies and procedures which include a determination of the need for the goods and services; preparation and evaluation of requests for proposals by supply chain management; the writing of contracts; controls and guidance regarding the evaluation of the proposals; and negotiation of contract terms and conditions. As appropriate, these contracts are also reviewed by individuals in the legal, accounting, and/or risk management/services departments prior to being approved by the responsible individual. The responsible individual will vary depending on the department requiring the goods and services, the dollar amount of the contract, and the appropriate individual within that department who has the authority to approve a contract of the applicable dollar amount.
Director Independence.
The board of directors of Gulf Power consists of seven non-employee directors (Ms. Deborah H. Calder and Messrs. Allan G. Bense, William C. Cramer, Jr., Julian B. MacQueen, J. Mort O'Sullivan, III, Michael T. Rehwinkel, and Winston E. Scott) and Mr. Connally.
Southern Company owns all of Gulf Power's outstanding common stock. Gulf Power has listed only debt securities on the NYSE. Accordingly, under the rules of the NYSE, Gulf Power is exempt from most of the NYSE's listing standards relating to corporate governance. Gulf Power has voluntarily complied with certain NYSE listing standards relating to corporate governance where such compliance was deemed to be in the best interests of Gulf Power's shareholders.
|
| |
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The following represents the fees billed to Georgia Power, Gulf Power, and Southern Power for the last two fiscal years by Deloitte & Touche LLP, each company's principal public accountant for 20152017 and 2014:
2016:
| | | 2015 | | 2014 | 2017 | | 2016 |
| (in thousands) | (in thousands) |
Georgia Power | | | | |
Audit Fees (1) | | $ | 3,247 |
| | $ | 3,154 |
|
Audit-Related Fees (2) | | 96 |
| | 30 |
|
Tax Fees | | — |
| | — |
|
All Other Fees (2)(3) | | 1 |
| | 15 |
|
Total | | $ | 3,344 |
| | $ | 3,199 |
|
Gulf Power | | | | | | |
Audit Fees (1) | $ | 1,359 |
| | $ | 1,427 |
| $ | 1,442 |
| | $ | 1,346 |
|
Audit-Related Fees | 2 |
| | — |
| 3 |
| | 3 |
|
Tax Fees | — |
| | — |
| — |
| | — |
|
All Other Fees (2)(3) | 1 |
| | 12 |
| |
All Other Fees (3) | | — |
| | 2 |
|
Total | $ | 1,362 |
| | $ | 1,439 |
| $ | 1,445 |
| | $ | 1,351 |
|
Southern Power | | | | | | |
Audit Fees (1) | $ | 1,478 |
| | $ | 1,143 |
| $ | 1,778 |
| | $ | 1,817 |
|
Audit-Related Fees | 3 |
| | — |
| 439 |
| | 372 |
|
Tax Fees | — |
| | — |
| — |
| | — |
|
All Other Fees (3) | 5 |
| | 2 |
| 8 |
| | 6 |
|
Total | $ | 1,486 |
| | $ | 1,145 |
| $ | 2,225 |
| | $ | 2,195 |
|
(1) Includes services performed in connection with financing transactions.
(2) Includes both audit and non-statutory audit services in 2017 and non-statutory audit services in 2016.
(3) Represents registration fees for attendance at Deloitte & Touche LLP-sponsored education seminars.
The following represents the fees billed to Southern Company Gas for the last two fiscal years by PricewaterhouseCoopers LLP, Southern Company Gas' principal public accountant through February 11, 2016, and Deloitte & Touche LLP, Southern Company Gas' principal public accountant since February 11, 2016:
|
| | | | | | | |
| 2017 | | 2016 |
| (in thousands) |
Southern Company Gas | | | |
Audit Fees (1) | $ | 4,449 |
| | $ | 5,131 |
|
Audit-Related Fees (2) | 579 |
| | 59 |
|
Tax Fees (3) | — |
| | 65 |
|
All Other Fees (4) | 8 |
| | 7 |
|
Total | $ | 5,036 |
| | $ | 5,262 |
|
| |
(1) | Includes services performedDeloitte & Touche LLP fees in connection with financing transactions.transactions and PricewaterhouseCoopers LLP and Deloitte & Touche LLP fees in connection with audits of several subsidiaries in addition to the consolidated audit. |
| |
(2) | Represents fees for non-statutory audit services in 2017 and a review report on internal controls provided to third parties billed by Deloitte & Touche LLP in 2017 and 2016. |
| |
(3) | Represents fees billed by Deloitte & Touche LLP for tax compliance services. |
| |
(4) | Represents registration fees for attendance at Deloitte & Touche-sponsoredTouche LLP-sponsored education seminars in 2014 and 2015, subscription fees for Deloitte & Touche'sTouche LLP's technical accounting research tool in 2014 and 2015, and information technology consulting services related to general ledger software of Gulf Power in 2014.tool. |
| |
(3) | Represents registration fees for attendance at Deloitte & Touche-sponsored education seminars in 2014 and 2015, subscription fees for Deloitte & Touche's technical accounting research tool in 2014 and 2015, and information technology consulting services related to general ledger software of Southern Power in 2014. |
The Southern Company Audit Committee (on behalf of Southern Company and its subsidiaries) adopted a Policy of Engagement of the Independent Auditor for Audit and Non-Audit Services that includes requirements for such Audit Committee to pre-approve audit and non-audit services provided by Deloitte & Touche LLP. All of the audit services provided by Deloitte & Touche LLP in fiscal years 20152017 and 20142016 (described in the footnotes to the table above) and related fees were approved in advance by the Southern Company Audit Committee.
Prior to the closing of the Merger, the Southern Company Gas Audit Committee had responsibility for appointing, setting compensation, and overseeing the work of Southern Company Gas' independent registered public accounting firm. In recognition of this responsibility, Southern Company Gas' Audit Committee adopted a policy that required specific Audit Committee approval before any services were provided by the independent registered public accounting firm. All of the audit services provided by PricewaterhouseCoopers LLP and Deloitte & Touche LLP in fiscal year 2016 (described in the footnotes to the table above) prior to the closing of the Merger and related fees were approved in advance by the Southern Company Gas Audit Committee.
III-38
PART IV
| |
Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| |
(a) | The following documents are filed as a part of this report on Form 10-K: |
| |
(1) | Financial Statements and Financial Statement Schedules: |
Management's Report on Internal Control Over Financial Reporting for Southern Company and Subsidiary Companies is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Alabama Power is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Georgia Power is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Gulf Power is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Mississippi Power is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Southern Power and Subsidiary Companies is listed under Item 8 herein.
Management's Report on Internal Control Over Financial Reporting for Southern Company Gas and Subsidiary Companies is listed under Item 8 herein.
Reports of Independent Registered Public Accounting Firm on the financial statements and financial statement schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, and Southern Company Gas and Subsidiary Companies, as well as the Report of Independent Registered Public Accounting Firm on the financial statements of Southern Power and Subsidiary Companies are listed under Item 8 herein.
The financial statements filed as a part of this report for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power and Subsidiary Companies, and Southern PowerCompany Gas and Subsidiary Companies are listed under Item 8 herein.
The financial statement schedules for Southern Company and Subsidiary Companies, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power, and Southern Company Gas and Subsidiary Companies are listed in the Index to the Financial Statement Schedules at page S-1.
The financial statements of Southern Natural Gas Company, L.L.C. as of December 31, 2017 and 2016 and for the year ended December 31, 2017 and the four months ended December 31, 2016 are provided by Southern Company Gas as separate financial statements of subsidiaries not consolidated pursuant to Rule 3-09 of Regulation S-X, and are incorporated by reference herein from Exhibit 99(g) hereto.
Exhibits for Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas are listed in the Exhibit Index at page E-1.
Item 16. FORM 10-K SUMMARY
None.
IV-1
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
THE SOUTHERN COMPANY |
| |
By: | Thomas A. Fanning |
| Chairman, President, and |
| Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Thomas A. Fanning
Chairman, President,
Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
Art P. Beattie
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
| | | |
| | | |
Ann P. Daiss
Comptroller and Chief Accounting Officer
(Principal Accounting Officer)
| | | |
Directors: | | |
Juanita Powell Baranco
Jon A. Boscia
Henry A. Clark III
David J. Grain
Veronica M. Hagen
Warren A. Hood, Jr.
Linda P. Hudson
| Donald M. James
John D. Johns
Dale E. Klein
William G. Smith, Jr.
Steven R. Specker
Larry D. Thompson
E. Jenner Wood III
| | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
ALABAMA POWER COMPANY |
| |
By: | Mark A. Crosswhite |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Mark A. Crosswhite
Chairman, President, Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
Philip C. Raymond
Executive Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
| | | |
| | | |
Anita Allcorn-Walker
Vice President and Comptroller
(Principal Accounting Officer)
| | | |
Directors: | | |
Whit Armstrong
Ralph D. Cook
David J. Cooper, Sr.
Grayson Hall
Anthony A. Joseph
Patricia M. King
James K. Lowder
| Malcolm Portera
Robert D. Powers
Catherine J. Randall
C. Dowd Ritter
James H. Sanford
R. Mitchell Shackleford, III
| | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
GEORGIA POWER COMPANY |
| |
By: | W. Paul Bowers |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
W. Paul Bowers
Chairman, President, Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
W. Ron Hinson
Executive Vice President, Chief Financial Officer,
Treasurer, and Corporate Secretary
(Principal Financial Officer)
| | | |
| | | |
David P. Poroch
Comptroller and Vice President
(Principal Accounting Officer)
| | | |
Directors: | | |
Robert L. Brown, Jr.
Anna R. Cablik
Stephen S. Green
Kessel D. Stelling, Jr.
Jimmy C. Tallent
| Charles K. Tarbutton
Beverly Daniel Tatum
D. Gary Thompson
Clyde C. Tuggle
Richard W. Ussery
| | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
GULF POWER COMPANY |
| |
By: | S. W. Connally, Jr. |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
S. W. Connally, Jr.
Chairman, President, Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
Xia Liu
Vice President and Chief Financial Officer
(Principal Financial Officer)
| | | |
| | | |
Janet J. Hodnett
Comptroller
(Principal Accounting Officer)
| | | |
Directors: | | |
Allan G. Bense | J. Mort O'Sullivan, III | | |
Deborah H. Calder | Michael T. Rehwinkel | | |
William C. Cramer, Jr. | Winston E. Scott | | |
Julian B. MacQueen | | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
MISSISSIPPI POWER COMPANY |
| |
By: | Anthony L. Wilson |
| President and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Anthony L. Wilson
President, Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
Moses H. Feagin
Vice President, Treasurer, and
Chief Financial Officer
(Principal Financial Officer)
| | | |
| | | |
Cynthia F. Shaw
Comptroller
(Principal Accounting Officer)
| | | |
Directors: | | |
Carl J. Chaney | Mark E. Keenum | | |
L. Royce Cumbest | Christine L. Pickering | | |
Thomas A. Dews | Phillip J. Terrell | | |
G. Edison Holland, Jr. | M. L. Waters | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
SOUTHERN POWER COMPANY |
| |
By: | Oscar C. Harper IV |
| President and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 26, 2016 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Oscar C. Harper IV
President, Chief Executive Officer, and Director
(Principal Executive Officer)
| | | |
| | | |
William C. Grantham
Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
| | | |
| | | |
Elliott L. Spencer
Comptroller and Corporate Secretary
(Principal Accounting Officer)
| | | |
Directors: | | |
Art P. Beattie | Mark S. Lantrip | | |
Thomas A. Fanning | Joseph A. Miller | | |
Kimberly S. Greene
| Christopher C. Womack | | |
James Y. Kerr II | | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 26, 2016
Supplemental Information to be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:
No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of the registrant during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2015.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors and Stockholders of
The Southern Company and Subsidiary Companies
Opinion on the Financial Statement Schedule
We have audited the consolidated financial statements of Southern Company and SubsidiariesSubsidiary Companies (the Company) as of
December 31, 20152017 and 2014,2016, and for each of the three years in the period ended December 31, 2015,2017, and the Company's internal control over financial reporting as of December 31, 2015,2017, and have issued our report thereon dated February 26, 201620, 2018; such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company (page S-2) listed in the Index at Item 15. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of
Alabama Power Company
Opinion on the Financial Statement Schedule
We have audited the financial statements of Alabama Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014,2016, and for each of the three years in the period ended December 31, 2015,2017, and have issued our report thereon dated February 26, 201620, 2018; such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (Page S-3) listed in the Index at Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/Deloitte & Touche LLP
Birmingham, Alabama
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of
Georgia Power Company
Opinion on the Financial Statement Schedule
We have audited the financial statements of Georgia Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014,2016, and for each of the three years in the period ended December 31, 2015,2017, and have issued our report thereon dated February 26, 201620, 2018; such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (Page S-4) listed in the Index at Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of
Gulf Power Company
Opinion on the Financial Statement Schedule
We have audited the financial statements of Gulf Power Company (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014,2016, and for each of the three years in the period ended December 31, 2015,2017, and have issued our report thereon dated February 26, 201620, 2018; such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (Page S-5) listed in the Index at Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statement schedule based on our audits. In our opinion, such financial statement schedule, when considered in relation to the financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 20, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Mississippi Power Company
Opinion on the Financial Statement Schedule
We have audited the financial statements of Mississippi Power Company (the Company) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2017 and 2016, and for each of the three years in the period ended December 31, 2017, and have issued our report thereon dated February 20, 2018; such report is included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company (Page S-6) listed in the Index at Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
Mississippi Power CompanyOpinion on the Financial Statement Schedule
We have audited the consolidated financial statements of Mississippi PowerSouthern Company Gas and Subsidiary Companies (the Company) (a wholly ownedwholly-owned subsidiary of The Southern Company) as of December 31, 20152017 and 2014,2016, and the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the periodyear ended December 31, 2015,2017 and the six-month periods ended June 30, 2016 (Predecessor) and December 31, 2016 (Successor), and have issued our report thereon dated February 26, 2016;20, 2018; such report is included elsewhere in this Form 10-K. As indicated in that report, we did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), the Company's investment in which is accounted for by the use of the equity method. The Company's consolidated financial statements include its equity investment in SNG of $1,262 million and $1,394 million as of December 31, 2017 and December 31, 2016, respectively, and its earnings from its equity method investment in SNG of $88 million and $56 million for the year ended December 31, 2017 and the six months ended December 31, 2016, respectively. Those statements were audited by other auditors whose report (which expresses an unqualified opinion on SNG's financial statements and contains an emphasis of matter paragraph concerning the extent of its operations and relationships with affiliated entities) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the report of the other auditors. Our audits also included the consolidated financial statement schedule of the Company (Page S-6)S-7) listed in the Index at Item 15. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/Deloitte & Touche LLP
Atlanta, Georgia
February 26, 201620, 2018
INDEX TO FINANCIAL STATEMENT SCHEDULES
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| Page |
Schedule II | |
Valuation and Qualifying Accounts and Reserves 2015, 2014,2017, 2016, and 20132015 | |
| S-2 |
| S-3 |
| S-4 |
| S-5 |
| S-6 |
| S-7 |
Schedules I through V not listed above are omitted as not applicable or not required. A Schedule II for Southern Power Company and Subsidiary Companies is not being provided because there were no reportable items for the three-year period ended December 31, 20152017. Columns omitted from schedules filed have been omitted because the information is not applicable or not required.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 20152017, 20142016, AND 20132015
(Stated in Thousands of Dollars)
| | | | | Additions | | | | | | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Acquisitions | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | | | | | | | | | | | | |
2017 | | $ | 43,429 |
| | $ | 55,770 |
| | $ | (248 | ) | | $ | 30 |
| | $ | 54,605 |
| | $ | 44,376 |
|
2016 | | 13,341 |
| | 39,959 |
| | (1,257 | ) | | 40,629 |
| | 49,243 |
| | 43,429 |
|
2015 | $ | 18,253 |
| | $ | 31,074 |
| | $ | — |
| | $ | 35,986 |
| | $ | 13,341 |
| 18,253 |
| | 31,074 |
| | — |
| | — |
| | 35,986 |
| | 13,341 |
|
2014 | 17,855 |
| | 43,537 |
| | — |
| | 43,139 |
| | 18,253 |
| |
2013 | 16,984 |
| | 36,788 |
| | — |
| | 35,917 |
| | 17,855 |
| |
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
ALABAMA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 20152017, 20142016, AND 20132015
(Stated in Thousands of Dollars)
| | | | | Additions | | | | | | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | | | | | | | | | | |
2017 | | $ | 10,487 |
| | $ | 9,367 |
| | $ | — |
| | $ | 11,075 |
| | $ | 8,779 |
|
2016 | | 9,597 |
| | 11,310 |
| | — |
| | 10,420 |
| | 10,487 |
|
2015 | $ | 9,143 |
| | $ | 13,500 |
| | $ | — |
| | $ | 13,046 |
| | $ | 9,597 |
| 9,143 |
| | 13,500 |
| | — |
| | 13,046 |
| | 9,597 |
|
2014 | 8,350 |
| | 14,309 |
| | — |
| | 13,516 |
| | 9,143 |
| |
2013 | 8,450 |
| | 12,327 |
| | — |
| | 12,427 |
| | 8,350 |
| |
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
GEORGIA POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 20152017, 20142016, AND 20132015
(Stated in Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | |
| | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | |
2015 | $ | 6,076 |
| | $ | 16,862 |
| | $ | — |
| | $ | 20,791 |
| | $ | 2,147 |
|
2014 | 5,074 |
| | 24,141 |
| | — |
| | 23,139 |
| | 6,076 |
|
2013 | 6,259 |
| | 18,362 |
| | — |
| | 19,547 |
| | 5,074 |
|
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
GULF POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2015, 2014, AND 2013
(Stated in Thousands of Dollars)
| | | | | Additions | | | | | | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | | | | | | | | | | |
2017 | | $ | 2,836 |
| | $ | 11,250 |
| | $ | — |
| | $ | 11,474 |
| | $ | 2,612 |
|
2016 | | 2,147 |
| | 14,476 |
| | — |
| | 13,787 |
| | 2,836 |
|
2015 | $ | 2,087 |
| | $ | 2,041 |
| | $ | — |
| | $ | 3,353 |
| | $ | 775 |
| 6,076 |
| | 16,862 |
| | — |
| | 20,791 |
| | 2,147 |
|
2014 | 1,131 |
| | 4,304 |
| | — |
| | 3,348 |
| | 2,087 |
| |
2013 | 1,490 |
| | 1,900 |
| | — |
| | 2,259 |
| | 1,131 |
| |
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
GULF POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2017, 2016, AND 2015
(Stated in Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | |
| | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | |
2017 | $ | 732 |
| | $ | 2,859 |
| | $ | — |
| | $ | 2,846 |
| | $ | 745 |
|
2016 | 775 |
| | 2,946 |
| | — |
| | 2,989 |
| | 732 |
|
2015 | 2,087 |
| | 2,041 |
| | — |
| | 3,353 |
| | 775 |
|
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
MISSISSIPPI POWER COMPANY
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 20152017, 20142016, AND 20132015
(Stated in Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | |
| | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | |
2015 | $ | 825 |
| | $ | (1,994 | ) | | $ | — |
| | $ | (1,456 | ) | | $ | 287 |
|
2014 | 3,018 |
| | 562 |
| | — |
| | 2,755 |
| | 825 |
|
2013 | 373 |
| | 3,757 |
| | — |
| | 1,112 |
| | 3,018 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Provision for uncollectible accounts | | | | | | | | | |
2017 | $ | 494 |
| | $ | 1,377 |
| | $ | — |
| | $ | 1,279 |
| | $ | 592 |
|
2016 | 287 |
| | 1,295 |
| | — |
| | 1,088 |
| | 494 |
|
2015(*) | 825 |
| | (1,994 | ) | | — |
| | (1,456 | ) | | 287 |
|
((Note) Note)Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
The refund ordered by the Mississippi PSC pursuant to the 2015 Mississippi Supreme Court decision relative to Mirror CWIP involved refunding all billed amounts to all historical customers and included an interest component. The refund of approximately $371 million was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(1,994), where risk of collectibility was offset by applying the refund to past due amounts. It was also of sufficient size to offset amounts previously written off in the 2012-2015 time frame, accounting for the net recoveries of $(1,456).
For more information regarding the 2015 decision of the Mississippi Supreme Court related to the Mirror CWIP refund in fourth quarter 2015, see Note 3 to the financial statement of Mississippi Power under "Integrated Coal Gasification Combined Cycle – 2013 MPSC Rate Order" in Item 8 herein.
| |
(*) | The refund ordered by the Mississippi PSC pursuant to the 2015 Mississippi Supreme Court decision relative to a regulatory liability used by Mississippi Power to record financing costs associated with construction of the Kemper County energy facility involved refunding all billed amounts to all historical customers and included an interest component. The refund of approximately $371 million in 2015 was of sufficient magnitude to resolve most past due amounts beyond 30 days aged receivables, accounting for the negative provision of $(2.0) million where risk of collectibility was offset by applying the refund to past due amounts. It was also of sufficient size to offset amounts previously written off in the 2012-2015 time frame, accounting for the net recoveries of $1.5 million. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
FOR THE SUCCESSOR PERIODS OF JULY 1, 2016 THROUGH DECEMBER 31, 2016
AND THE YEAR ENDED DECEMBER 31, 2017
AND THE PREDECESSOR PERIODS OF JANUARY 1, 2016 THROUGH JUNE 30, 2016
AND THE YEAR ENDED DECEMBER 31, 2015
(Stated in Thousands of Dollars)
|
| | | | | | | | | | | | | | | | | | | |
| | | Additions | | | | |
Description | Balance at Beginning of Period | | Charged to Income | | Charged to Other Accounts | | Deductions (Note) | | Balance at End of Period |
Successor – December 31, 2017 | | | | | | | | | |
Provision for uncollectible accounts | $ | 27,316 |
| | $ | 28,022 |
| | $ | (248 | ) | | $ | 27,286 |
| | $ | 27,804 |
|
Income tax valuation | 19,182 |
| | — |
| | — |
| | 7,910 |
| | 11,272 |
|
Successor – December 31, 2016 | | | | | | | | | |
Provision for uncollectible accounts | $ | 37,663 |
| | $ | 9,500 |
| | $ | (1,257 | ) | | $ | 18,590 |
| | $ | 27,316 |
|
Income tax valuation | 19,182 |
| | — |
| | — |
| | — |
| | 19,182 |
|
Predecessor – June 30, 2016 | | | | | | | | | |
Provision for uncollectible accounts | $ | 29,142 |
| | $ | 15,976 |
| | $ | 1,608 |
| | $ | 9,063 |
| | $ | 37,663 |
|
Income tax valuation | 19,182 |
| | — |
| | — |
| | — |
| | 19,182 |
|
Predecessor – 2015 | | | | | | | | | |
Provision for uncollectible accounts | $ | 35,069 |
| | $ | 27,050 |
| | $ | 3,017 |
| | $ | 35,994 |
| | $ | 29,142 |
|
Income tax valuation | 19,637 |
| | — |
| | — |
| | 455 |
| | 19,182 |
|
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off.
EXHIBIT INDEX
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements required to be identified as such by Item 15 of Form 10-K. |
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(2) | | Plan of acquisition, reorganization, arrangement, liquidation or succession |
| | Southern Company |
| | | (a) | | 1 | | — | | |
| | Southern Company Gas |
| | | (g) | | 1 | | — | | Agreement and Plan of Merger by and among Southern Company, AMS Corp., and Southern Company Gas, dated August 23, 2015. See Exhibit 2(a)1 herein. |
| | | (g) | | 2 | | — | | |
| | | (g) | | 3 | | — | | |
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(3) | | Articles of Incorporation and By-Laws |
| | Southern Company |
| | | (a) | | 1 | | — | | Composite Certificate of Incorporation of Southern Company, reflecting all amendments thereto through May 27, 2010.26, 2016. (Designated in Registration No. 33-3546 as Exhibit 4(a), in Certificate of Notification, File No. 70-7341, as Exhibit A, in Certificate of Notification, File No. 70-8181, as Exhibit A, and in Form 8-K dated May 26, 2010, File No. 1-3526, as Exhibit 3.1.3.1, and in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.1.) |
| | | (a) | | 2 | | — | | |
| | Alabama Power |
| | | (b) | | 1 | | — | | Charter of Alabama Power and amendments thereto through April 25, 2008.September 7, 2017. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in Alabama Power's Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2, in Alabama Power's Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)1, in Form 8-K dated February 5, 2004, File No. 1-3164, as Exhibit 4.4, in Alabama Power's Form 10-Q for the quarter ended March 31, 2006, File No. 1-3164, as Exhibit 3(b)(1), in Form 8-K dated December 5, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 12, 2007, File No. 1-3164, as Exhibit 4.5, in Form 8-K dated October 17, 2007, File No. 1-3164, as Exhibit 4.5 and, in Alabama Power's Form 10-Q for the quarter ended March 31, 2008, File No. 1-3164, as Exhibit 3(b)1.1, and in Form 8-K dated September 5, 2017, File No. 1-3164, as Exhibit 4.1.) |
| | | (b) | | 2 | | — | | |
|
| | | | | | | | | | |
| | Georgia Power |
| | | (c) | | 1 | | — | | Charter of Georgia Power and amendments thereto through October 9, 2007. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in Georgia Power's Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in Georgia Power's Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2, in Georgia Power's Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2, in Form 8-K dated June 27, 2006, File No. 1-6468, as Exhibit 3.1, and in Form 8-K dated October 3, 2007, File No. 1-6468, as Exhibit 4.5.4.5.) |
| | | (c) | | 2 | | — | | |
|
| | | | | | | | | | |
| | Gulf Power |
| | | (d) | | 1 | | — | | Amended and Restated Articles of Incorporation of Gulf Power and amendments thereto through June 17, 2013. (Designated in Form 8-K dated October 27, 2005, File No. 001-31737, as Exhibit 3.1, in Form 8-K dated November 9, 2005, File No. 001-31737, as Exhibit 4.7, in Form 8-K dated October 16, 2007, File No. 001-31737, as Exhibit 4.5, and in Form 8-K dated June 10, 2013, File No. 001-31737, as Exhibit 4.7.) |
| | | (d) | | 2 | | — | | |
| | Mississippi Power |
| | | (e) | | 1 | | — | | Articles of Incorporation of Mississippi Power, articles of merger of Mississippi Power Company (a Maine corporation) into Mississippi Power and articles of amendment to the articles of incorporation of Mississippi Power through April 2, 2004. (Designated in Registration No. 2-71540 as Exhibit 4(a)-1, in Form U5S for 1987, File No. 30-222-2, as Exhibit B-10, in Registration No. 33-49320 as Exhibit 4(b)-(1), in Form 8-K dated August 5, 1992, File No. 001-11229, as Exhibits 4(b)-2 and 4(b)-3, in Form 8-K dated August 4, 1993, File No. 001-11229, as Exhibit 4(b)-3, in Form 8-K dated August 18, 1993, File No. 001-11229, as Exhibit 4(b)-3, in Mississippi Power's Form 10-K for the year ended December 31, 1997, File No. 001-11229, as Exhibit 3(e)2, in Mississippi Power's Form 10-K for the year ended December 31, 2000, File No. 001-11229, as Exhibit 3(e)2, and in Form 8-K dated March 3, 2004, File No. 001-11229, as Exhibit 4.6.4.6.) |
| | | (e) | | 2 | | — | | |
| | Southern Power |
| | | (f) | | 1 | | — | | |
| | | (f) | | 2 | | — | | |
| | Southern Company Gas |
| | | (f) | | 1 | | — | | |
| | | (f) | | 2 | | — | | |
| | | | | | | | | |
(4) | | Instruments Describing Rights of Security Holders, Including Indentures |
| | With respect to each of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company, and Southern Company Gas, such registrant has not included any instrumentexcluded certain instruments with respect to long-term debt that does not exceed 10% of the total assets of such registrant and its subsidiaries. Each such registrant agrees, upon request of the SEC, to furnish copies of any or all such instruments to the SEC. |
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| | Southern Company |
| | | (a) | | 1 | | — | | Senior Note Indenture dated as of January 1, 2007, between Southern Company and Wells Fargo Bank, National Association, as Trustee, and certain indentures supplemental thereto through June 12, 2015.21, 2017. (Designated in Form 8-K dated January 11, 2007, File No. 1-3526, as ExhibitsExhibit 4.1 and 4.2, , in Form 8-K dated March 20, 2007, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated August 13, 2008, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated May 11, 2009, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated October 19, 2009, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated September 13, 2010, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated August 16, 2011, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated August 21, 2013, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated August 19, 2014, File No. 1-3526, as Exhibits 4.2(a) andExhibit 4.2(b), and in Form 8-K dated June 9, 2015, File No. 1-3526, as Exhibit 4.2.4.2, in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(a), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(b), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(c), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(d), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g), and in Form 10-Q for the quarter ended June 30, 2017, File No. 1-3526, as Exhibit 4(a)2.) |
| | | (a) | | 2 | | — | | Subordinated Note Indenture dated as of October 1, 2015, between The Southern Company and Wells Fargo Bank, National Association, as Trustee, and indentures supplemental thereto through October 8, 2015.November 22, 2017. (Designated in Form 8-K dated October 1, 2015, File No. 1-3526, as ExhibitsExhibit 4.3, in Form 8-K dated October 1, 2015, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated September 12, 2016, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated December 5, 2016, File No. 1-3526, as Exhibit 4.4, in Form 10-Q for the quarter ended June 30, 2017, File No. 1-3526 as Exhibit 4(a)1, and 4.4.in Form 8-K dated November 17, 2017, File No. 1-3526, as Exhibit 4.4.) |
| | Alabama Power |
| | | (b) | | 1 | | — | | Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through October 2, 2002. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1, and 4.2, in Form 8-K dated February 18, 1999, File No. 1-3164, as Exhibit 4.2, and in Form 8-K dated September 26, 2002, File No. 3164, as Exhibits 4.9-A and 4.9-B.Exhibit 4.9-B.) |
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| | | (b) | | 2 | | — | | Senior Note Indenture dated as of December 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through January 13, 2016.November 8, 2017. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as ExhibitsExhibit 4.1 and 4.2, in Form 8-K dated February 20, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 17, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 11, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 8, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 16, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 7, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 28, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 12, 1998, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 19, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 13, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 21, 1999, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 11, 2000, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 22, 2001, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated June 21, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated October 16, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated November 20, 2002, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated December 6, 2002, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 11, 2003, File No. 1-3164, as ExhibitsExhibit 4.2(a) and 4.2(b), in Form 8-K dated February 11, 2003, File No. 1-3164, as Exhibit 4.2(b), in Form 8-K dated March 12, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 15, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 1, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 10, 2004, File No. 1-3164, as Exhibit 4.2 in Form 8-K dated April 7, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 19, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 9, 2004, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated March 8, 2005, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 11, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 13, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 1, 2006, File No. 1-3164, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated March 9, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated June 7, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated January 30, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated April 4, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 11, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated December 4, 2007, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 8, 2008, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 14, 2008, File No. 1-3164 as Exhibit 4.2, in Form 8-K dated February 26, 2009, File No. 1-3164 as Exhibit 4.2, in Form 8-K dated September 27, 2010, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated March 3, 2011, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 18, 2011, File No. 1-3164, as ExhibitsExhibit 4.2(a) and 4.2(b), in Form 8-K dated May 18, 2011, File No. 1-3164, as Exhibit 4.2(b),in Form 8-K dated January 10, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated October 9, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 27, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated December 3, 2013, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 20, 2014, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated March 5, 2015, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated April 9, 2015, File No. 1-3164, as Exhibit 4.6(b), and in Form 8-K dated January 8, 2016, File No. 1-3164, as Exhibit 4.6.4.6, in Form 8-K dated February 27, 2017, File No. 1-3164, as Exhibit 4.6, and in Form 8-K dated November 2, 2017, File No. 1-3164, as Exhibit 4.6.) |
| | | (b) | | 3 | | — | | |
| | | (b) | | 4 | | — | | |
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| | Georgia Power |
| | | (c) | | 1 | | — | | Senior Note Indenture dated as of January 1, 1998, between Georgia Power and Wells Fargo Bank, National Association, as Successor Trustee, and certain indentures supplemental thereto through December 4, 2015.August 8, 2017. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1 and 4.2, in Forms 8-K each dated November 19, 1998, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 3, 1999, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated February 15, 2000, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated January 26, 2001, File No. 1-6469 as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 16, 2001, File No. 1-6469 as Exhibit 4.2, in Form 8-K dated May 1, 2001, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 27, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 15, 2002, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 13, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 21, 2003, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated April 10, 2003, File No. 1-6468, as Exhibits 4.1, 4.2 and 4.3, in Form 8-K dated September 8, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated September 23, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated January 12, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2, in Form 8-K dated February 12, 2004, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated August 11, 2004, File No. 1-6468, as Exhibits 4.1 and 4.2, in Form 8-K dated January 13, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated April 12, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated November 30, 2005, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated December 8, 2006, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 6, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 4, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated June 18, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated July 10, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated August 24, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 29, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 12,May 27, 2008, File No. 1-6468, as Exhibit 4.2 in Form 8-K dated June 5, 2008, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 12, 2008, File No. 1-6468, as Exhibits 4.2(a) and 4.2(b), in Form 8-K dated February 4, 2009, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated December 8, 2009, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 9, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated May 24, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated August 26, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated September 20, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated January 13, 2011, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated April 12, 2011, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 29, 2012, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated May 8, 2012, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated August 7, 2012, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated November 8, 2012, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 12, 2013, File No. 1-6468, as ExhibitsExhibit 4.2(a) and 4.2(b), in Form 8-K dated August 12, 2013, File No. 1-6468, as Exhibit 4.2, and in Form 8-K dated December 1, 2015, File No. 1-6468, as Exhibit 4.2.4.2, in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(b), and in Form 8-K dated August 3, 2017, File No. 1-6468, as Exhibit 4.2.) |
| | | (c) | | 2 | | — | | Loan Guarantee AgreementSubordinated Note Indenture, dated as of September 1, 2017, between Georgia Power and the DOE datedWells Fargo Bank, National Association, as of February 20, 2014Trustee, and Amendment No. 1First Supplemental Indenture thereto dated as of June 4, 2015.September 21, 2017. (Designated in Form 8-K dated February 20, 2014,September 18, 2017, File No. 1-6468, as Exhibit 4.14.3, and in Georgia Power's Form 10-Q for the quarter ended June 30, 2015,8-K dated September 18, 2017, File No. 1-6468, as Exhibit 10(c)1.4.4.) |
| | | (c) | | 3 | | — | | Loan Guarantee Agreement between Georgia Power and the DOE dated as of February 20, 2014, Amendment No. 1 thereto dated as of June 4, 2015, Amendment No. 2 thereto dated as of March 9, 2016, Amendment No. 3 thereto dated as of July 27, 2017, and Amendment No. 4 thereto dated as of December 8, 2017. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.1, in Form 10-Q for the quarter ended June 30, 2015, File No. 1-6468, as Exhibit 10(c)1, in Form 10-Q for the quarter ended March 31, 2016, File No. 1-6468, as Exhibit 4(c)3, in Form 8-K dated July 27, 2017, File No. 1-6468, as Exhibit 4.1, and in Form 8-K dated December 8, 2017, File No. 1-6468, as Exhibit 4.1.) |
| | | (c) | | 4 | | — | | |
| | | (c) | | 4 | | — | | Future Advance Promissory Note dated February 20, 2014 made by Georgia Power to the FFB. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.3.) |
| | | (c) | | 5 | | — | | |
| | | (c) | | 6 | | — | | |
| | | (c) | | 67 | | — | | |
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| | Gulf Power |
| | | (d) | | 1 | | — | | Senior Note Indenture dated as of January 1, 1998, between Gulf Power and Wells Fargo Bank, National Association, as Successor Trustee, and certain indentures supplemental thereto through September 23, 2014.May 18, 2017. (Designated in Form 8-K dated June 17, 1998, File No. 0-2429, as Exhibits 4.1 and 4.2, in Form 8-K dated August 17, 1999, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 31, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated October 5, 2001, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated January 18, 2002, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated March 21, 2003, File No. 0-2429, as Exhibit 4.2, in Form 8-K dated July 10, 2003, File No. 001-31737, as Exhibits 4.1 and 4.2, in Form 8-K dated September 5, 2003, File No. 001-31737, as Exhibit 4.1, in Form 8-K dated April 6, 2004, File No. 001-31737, as Exhibit 4.1, in Form 8-K dated September 13, 2004, File No. 001-31737, as Exhibit 4.1, in Form 8-K dated August 11, 2005, File No. 001-31737, as Exhibit 4.1, in Form 8-K dated October 27, 2005, File No. 001-31737, as Exhibit 4.1, in Form 8-K dated November 28, 2006, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated June 5, 2007, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated June 22, 2009, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated April 6, 2010, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated September 9, 2010, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated May 12, 2011, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated May 15, 2012, File No. 001-31737, as Exhibit 4.2, in Form 8-K dated June 10, 2013, File No. 001-31737, as Exhibit 4.2 and, in Form 8-K dated September 16, 2014, File No. 001-31737, as Exhibit 4.2.4.2, and in Form 8-K dated May 15, 2017, File No. 001-31737, as Exhibit 4.2.) |
| | Mississippi Power |
| | | (e) | | 1 | | — | | Senior Note Indenture dated as of May 1, 1998, between Mississippi Power and Wells Fargo Bank, National Association, as Successor Trustee, and certain indentures supplemental thereto through March 9, 2012. (Designated in Form 8-K dated May 14, 1998, File No. 001-11229, as ExhibitsExhibit 4.1 4.2(a) and 4.2(b), in Form 8-K dated March 22, 2000, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated March 12, 2002, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated April 24, 2003, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated March 3, 2004, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated June 24, 2005, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated November 8, 2007, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated November 14, 2008, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated March 3, 2009, File No. 001-11229, as Exhibit 4.2, in Form 8-K dated October 11, 2011, File No. 001-11229, as Exhibits 4.2(a) andExhibit 4.2(b), and in Form 8-K dated March 5, 2012, File No. 001-11229, as Exhibit 4.2(b).) |
| | | (e) | | 2 | | — | | |
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| | Southern Power |
| | | (f) | | 1 | | — | | Senior Note Indenture dated as of June 1, 2002, between Southern Power Company and Wells Fargo Bank, National Association, as Successor Trustee, and certain indentures supplemental thereto through November 17, 2015.16, 2016. (Designated in Registration No. 333-98553 as ExhibitsExhibit 4.1 and 4.2 and, in Southern Power Company's Form 10-Q for the quarter ended June 30, 2003, File No. 333-98553, as Exhibit 4(g)1, in Form 8-K dated November 13, 2006, File No. 333-98553, as Exhibit 4.2, in Form 8-K dated September 14, 2011, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated July 10, 2013, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated May 14, 2015, File No. 333-98553, as ExhibitsExhibit 4.4(a) and, in Form 8-K dated May 14, 2015, File No. 333-98553, as Exhibit 4.4(b), and in Form 8-K dated November 12, 2015, File No. 333-98553, as Exhibit 4.4(a), in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(a), in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(b), in Form 10-Q for the quarter ended September 30, 2016, File No. 001-37803, as Exhibit 4(f)1, in Form 10-Q for the quarter ended September 30, 2016, File No. 001-37803, as Exhibit 4(f)2, in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(a), in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(b), and in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(c).) |
| | * | (f) | | 2 | | — | | |
| | Southern Company Gas |
| | | (g) | | 1 | | — | | |
| | | (g) | | 2 | | — | | Southern Company Gas Capital Corporation's 6.00% Senior Notes due 2034, 5.25% Senior Notes due 2019, Form of 3.50% Senior Notes due 2021, 5.875% Senior Notes due 2041, Form of Series B Senior Notes due 2018, 4.40% Senior Notes due 2043, 3.875% Senior Notes due 2025, 3.250% Senior Notes due 2026, Form of 2.450% Senior Note due October 1, 2023, Form of 3.950% Senior Note due October 1, 2046, and Form of Series 2017A 4.400% Senior Note due May 30, 2047. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated August 5, 2009, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated September 15, 2011, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated March 16, 2011, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated August 31, 2011, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.1(a), in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.1(b), and in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.1, respectively.) |
| | | (g) | | 3 | | — | | Southern Company Gas' Guarantee related to the 6.00% Senior Notes due 2034, Guarantee related to the 5.25% Senior Notes due 2019, Guarantee related to the 5.875% Senior Notes due 2041, Form of Guarantee related to the 3.50% Senior Notes due 2021, Guarantee related to the 4.40% Senior Notes due 2043, Guarantee related to the 3.875% Senior Notes due 2025, Guarantee related to the 3.250% Senior Notes due 2026, Form of Guarantee related to the 2.450% Senior Notes due October 1, 2023, Form of Guarantee related to the 3.950% Senior Notes due October 1, 2046, and Form of Guarantee related to the Series 2017A 4.400% Senior Notes due May 30, 2047. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated March 16, 2011, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated September 15, 2011, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.3(a), in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.3(b), and in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.3, respectively.) |
| | | (g) | | 4 | | — | | Indenture dated December 1, 1989 of Atlanta Gas Light Company and First Supplemental Indenture thereto dated March 16, 1992. (Designated in Form S-3, File No. 33-32274, as Exhibit 4(a) and in Form S-3, File No. 33-46419, as Exhibit 4(a).) |
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| | | (g) | | 5 | | — | | Indenture of Commonwealth Edison Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated as of January 1, 1954, Indenture of Adoption of Northern Illinois Gas Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated February 9, 1954, and certain indentures supplemental thereto. (Designated in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.02, in Registration No. 2-56578 as Exhibits 4.4(a)2.21 and 4.4(b)2.25, in Form 10-Q for the quarter ended June 30, 1996, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1997, File No. 1-7296, as Exhibit 4.19, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.09, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.10, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.11, in Form 10-K for the year ended December 31, 2006, File No. 1-7296, as Exhibit 4.11, in Form 10-Q for the quarter ended September 30, 2008, File No. 1-7296, as Exhibit 4.01, in Form 10-Q for the quarter ended June 31, 2009, File No. 1-7296, as Exhibit 4.01, in Form 10-Q for the quarter ended September 30, 2012, File No. 1-7296, as Exhibit 4, and in Form 10-K for the year ended December 31, 2016, File No. 1-14174, as Exhibit 4(g)6.) |
| | * | (g) | | 6 | | — | | |
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(10) | | Material Contracts |
| | Southern Company |
| | # | (a) | | 1 | | — | | |
| | # | (a) | | 2 | | — | | |
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| | # * | (a) | | 4 | | — | | |
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| | # | (a) | | 5 | | — | | The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2016, File No. 1-3526, as Exhibit 10(a)1 and in Form 10-K for the year ended December 31, 2008,2016, File No. 1-3526,13536, as Exhibit 10(a)6 and in Southern Company's Form 10-K for the year ended December 31, 2009, File No. 1-3526, as Exhibit 10(a)(8)18.) |
| | # | (a) | | 6 | | — | | The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. (Designated in Southern Company's Form 10-Q for the quarter ended June 30, 2016, File No. 1-3526, as Exhibit 10(a)2 and in Form 10-K for the year ended December 31, 2008,2016, File No. 1-3526,13536, as Exhibit 10(a)7 and in Southern Company's Form 10-K for the year ended December 31, 2009, File No. 1-3526, as Exhibit 10(a)10.19.) |
| | # | (a) | | 7 | | — | | |
| | # | (a) | | 8 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless,Southern Linc, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)103 and in Southern Company's Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)16.16.) |
| | # | (a) | | 9 | | — | | Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. (Designated in Southern Company's Form 10-K for the year ended December 31, 2000, File No. 1-3526, as Exhibit 10(a)104 and in Southern Company's Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)18.18.) |
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| | # | (a) | | 10 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective September 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)92 and in Southern Company's Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)20.20.) |
| | # | (a) | | 11 | | — | | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. (Designated in Southern Company's Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)23, in Southern Company's Form 10-K for the year ended December 31, 2009, File No. 1-3526, as Exhibit 10(a)22, and in Southern Company's Form 10-K for the year ended December 31, 2010, File No. 1-3526, as Exhibit 10(a)16.16.) |
| | # | (a) | | 12 | | — | | |
| | # | (a) | | 13 | | — | | |
| | # | (a) | | 14 | | — | | Retention and Restricted Stock Unit Award Agreement between Southern Nuclear and Stephen E. Kuczynski effective as of July 11, 2011. (Designated in Form 10-Q for the quarter ended March 31, 2013, File No. 1-3526, as Exhibit 10(a)3.) |
| | # | (a) | | 15 | | — | | Retention Award Agreement between Southern Nuclear and Stephen E. Kuczynski effective as of October 20, 2014. (Designated in Form 10-Q for the quarter ended March 31, 2015, File No. 1-3526, as Exhibit 10(a)1.) |
| | # | (a) | | 16 | | — | | |
| | # | (a) | | 15 | | — | | |
| | # * | (a) | | 16 | | — | | |
| | # * | (a) | | 17 | | — | | Commitment Letter dated August 23, 2015. (Designated in Form 8-K dated August 23, 2015, File No. 1-3526, as Exhibit 10.1.) |
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| | | (a) | | 18 | | — | | Bridge Credit Agreement dated as of September 30, 2015, amongThe Southern Company as the Borrower, the Lenders identified therein,Employee Savings Plan, Amended and Citibank, N.A., as Administrative Agent.Restated effective January 1, 2018. (Designated in Post-Effective Amendment No. 1 to Form 8-K dated September 30, 2015,S-8, File No. 1-3526,333-212783 as Exhibit 10.1.4.3.) |
| | # * | (a) | | 19 | | — | | Second Amendment to The |
| | # * | (a) | | 20 | | — | | Second Amendment to The |
| | # * | (a) | | 21 | | — | | Second Amendment to The |
| | Alabama Power |
| | | (b) | | 1 | | — | | Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS. (Designated in Form 10-Q for the quarter ended March 31, 2007, File No. 1-3164, as Exhibit 10(b)5.5.) |
| | # | (b) | | 2 | | — | | Southern Company 2011 Omnibus Incentive Compensation Plan effective May 25, 2011. See Exhibit 10(a)1 herein. |
| | # | (b) | | 3 | | — | | Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein. |
| | # | (b) | | 4 | | — | | Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2009 and First Amendment thereto effective January 1, 2010.2018. See Exhibit 10(a)4 herein. |
| | # | (b) | | 5 | | — | | The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. See Exhibit 10(a)5 herein. |
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| | # | (b) | | 6 | | — | | The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. See Exhibit 10(a)6 herein. |
| | # | (b) | | 7 | | — | | Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)12 herein. |
| | # | (b) | | 8 | | — | | |
| | # | (b) | | 9 | | — | | The Southern Company Change in Control Benefits Protection Plan (an amendment and restatement of The Southern Company Change in Control Benefit Plan Determination Policy), effective December 31, 2008. See Exhibit 10(a)7 herein. |
| | # | (b) | | 10 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless,Southern Linc, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)8 herein. |
| | # | (b) | | 11 | | — | | Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)9 herein. |
| | # | (b) | | 12 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective September 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)10 herein. |
| | # | (b) | | 13 | | — | | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. See Exhibit 10(a)11 herein. |
| | # | (b) | | 14 | | — | | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)13 herein. |
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| | # | (b) | | 15 | | — | | |
| | # | (b) | | 16 | | — | | Retention AwardDeferred Compensation Agreement between Southern Company, SCS, Alabama Power, and Steven R. SpencerMark A. Crosswhite, effective July 30, 2008. See Exhibit 10(a)15 2013. (Designated in Form 10-Q for the quarter ended September 30, 2013, File No. 1-3164, as Exhibit 10(b)1.)herein. |
| | # | (b) | | 17 | | — | | Outside Directors Stock Plan for The Southern Company and its Subsidiaries effective June 1, 2015. See Exhibit 10(a)1614 herein. |
| | # | (b) | | 18 | | — | | Second Amendment to The Southern Company Supplemental Executive Retirement Plan effective January 2, 2016.1, 2018. See Exhibit 10(a)1916 herein. |
| | # | (b) | | 19 | | — | | Second Amendment to The Southern Company Supplemental Benefit Plan effective January 2, 2016.1, 2018. See Exhibit 10(a)2017 herein. |
| | # | (b) | | 20 | | — | | Second Amendment to TheForm of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company Deferred2011 Omnibus Incentive Compensation Plan effective October 29, 2014.Plan. See Exhibit 10(a)2119 herein. |
| | # * | (b) | | 21 | | — | | Employment Agreement between Alabama Power and Steven R. Spencer effective April 1, 2016.Form of Time-Vesting Restricted Stock Unit Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)21 herein. |
| | Georgia Power |
| | | (c) | | 1 | | — | | Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS. See Exhibit 10(b)1 herein. |
| | | (c) | | 2 | | — | | Revised and Restated Integrated Transmission System Agreement dated as of November 12, 1990, between Georgia Power and OPC. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(g).) |
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| | | (c) | | 3 | | — | | Revised and Restated Integrated Transmission System Agreement between Georgia Power and Dalton dated as of December 7, 1990. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(gg).) |
| | | (c) | | 4 | | — | | Revised and Restated Integrated Transmission System Agreement between Georgia Power and MEAG Power dated as of December 7, 1990. (Designated in Georgia Power's Form 10-K for the year ended December 31, 1990, File No. 1-6468, as Exhibit 10(hh).) |
| | # | (c) | | 5 | | — | | SouthernInterim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse Electric Company 2011 Omnibus Incentive Compensation Plan effectiveLLC, WECTEC Staffing Services LLC, and WECTEC Global Project Services, Inc., Amendment 1 thereto dated as of April 28, 2017, Amendment 2 thereto dated as of May 25, 2011. See12, 2017, Amendment 3 thereto dated as of June 3, 2017, Amendment 4 thereto dated as of June 5, 2017, Amendment 5 thereto dated as of March 29, 2017, Amendment 6 thereto dated as of June 22, 2017, Amendment 7 thereto dated as of June 28, 2017 and Amendment 8 thereto dated as of July 20, 2017. (Designated in Form 10-Q for the quarter ended March 31, 2017, File No. 1-6468, as Exhibit 10(a)1 herein.10(c)3, in Form 10-Q for the quarter ended March 31, 2017, File No. 1-6468, as Exhibit 10(c)4, in Form 8-K dated May 12, 2017, File No. 1-6468, as Exhibit 10.1, in Form 8-K dated June 3, 2017, File No. 1-6468, as Exhibit 10.1, in Form 8-K dated June 5, 2017, File No. 1-6468, as Exhibit 10.1, in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.2, in Form 8-K dated June 22, 2017, File No. 1-6468, as Exhibit 10.1, in Form 8-K dated June 28, 2017, File No. 1-6468, as Exhibit 10.1, and in Form 8-K dated July 20, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | # | (c) | | 6 | | — | | Settlement Agreement dated as of June 9, 2017, by and among Georgia Power, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Toshiba Corporation and Amendment No. 1 thereto dated as of December 8, 2017. (Designated in Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10(a)2 herein.10.1 and in Form 8-K dated December 8, 2017, File No. 1-6468, as Exhibit 10.1.) |
| | # | (c) | | 7 | | — | | Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)4 herein. |
| | # | (c) | | 8 | | — | | The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)5 herein. |
| | # | (c) | | 9 | | — | | The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)6 herein. |
| | # | (c) | | 10 | | — | | Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)12 herein. |
| | # | (c) | | 11 | | — | | Deferred Compensation Plan For Outside Directors of Georgia Power Company, Amended and Restated Effective January 1, 2008 and First Amendment thereto effective April 1, 2015. (Designated in Form 10-K for the year ended December 31, 2007, File No. 1-6468, as Exhibit 10(c)12 and in Form 10-Q for the quarter ended March 31, 2015, File No. 1-6468, as Exhibit 10(c)2.) |
| | # | (c) | | 12 | | — | | The Southern Company Change in Control Benefits Protection Plan (an amendment and restatement of The Southern Company Change in Control Benefit Plan Determination Policy), effective December 31, 2008. See Exhibit 10(a)7 herein. |
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| | # | (c) | | 13 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)8 herein. |
| | # | (c) | | 14 | | — | | Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)9 herein. |
| | # | (c) | | 15 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective September 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)10 herein. |
| | # | (c) | | 16 | | — | | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. See Exhibit 10(a)11 herein. |
| | | (c) | | 17 | | — | | Engineering, Procurement and ConstructionServices Agreement dated as of April 8, 2008, betweenJune 20, 2017, by and among Georgia Power, for itself and as agent for OPC,Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, as owners,acting by and a consortium consistingthrough its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse Electric Company LLC and Stone & Webster,WECTEC Global Project Services, Inc., as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site, Amendment No. 1 thereto dated as of December 11, 2009, Amendment No. 2 thereto dated as of January 15, 2010, Amendment No. 3 thereto dated as of February 23, 2010, Amendment No. 4 thereto dated as of May 2, 2011, Amendment No. 5 thereto dated as of February 7, 2012, and Amendment No. 6 thereto dated as of January 23, 2014. (Georgia Power requested confidential treatment for certain portions of these documentsthis document pursuant to applicationsan application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filingsfiling and filed them separately with the SEC.) (Designated in Form 10-Q/A for the quarter ended June 30, 2008, File No. 1-6468, as Exhibit 10(c)1, in Form 10-K for the year ended December 31, 2009, File No. 1-6468, as Exhibit 10(c)29, in Georgia Power's Form 10-Q for the quarter ended March 31, 2010, File No. 1-6468, as Exhibits 10(c)1 and 10(c)2, in Georgia Power's Form 10-Q for the quarter ended June 30, 2011,2017, File No. 1-6468, as Exhibit 10(c)2, in Georgia Power's Form 10-Q for the quarter ended March 31, 2012, File No. 1-6468, as Exhibit 10(c)2, and in Georgia Power's Form 10-Q for the quarter ended March 31, 2014, File No. 1-6468, as Exhibit 10(c)2.9.) |
| | #* | (c) | | 188 | | — | | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)13 herein. |
| | # | (c) | | 19 | | — | | Retention Award Agreement and Amendment thereto between Southern Nuclear and Joseph A. Miller effective January 1, 2013. (Designated in Form 10-K for the year ended December 31, 2012, File No. 1-6468, as Exhibits 10(c)24 and 10(c)25.) |
| | # | (c) | | 20 | | — | | Deferred Compansation Agreement between Southern Company, Southern Company Services, Inc., and John L. Pemberton, effective October 10, 2008. (Designated in Form 10-Q for the quarter ended March 31, 2015, File No. 1-6468, as Exhibit 10(c)3.) |
| | # | (c) | | 21 | | — | | Outside Directors Stock Plan for The Southern Company and its Subsidiaries effective June 1, 2015. See Exhibit 10(a)16 herein. |
| | # | (c) | | 22 | | — | | Second Amendment to The Southern Company Supplemental Executive Retirement Plan effective January 2, 2016. See Exhibit 10(a)19 herein. |
| | # | (c) | | 23 | | — | | Second Amendment to The Southern Company Supplemental Benefit Plan effective January 2, 2016. See Exhibit 10(a)20 herein. |
| | # | (c) | | 24 | | — | | Second Amendment to The Southern Company Deferred Compensation Plan effective October 29, 2014. See Exhibit 10(a)21 herein. |
| | * | (c) | | 25 | | — | | Amendment No. 7 dated as of January 8, 2016, to Engineering, Procurement and Construction Completion Agreement dated as of April 8, 2008,October 23, 2017, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse Electric CompanyMEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and CB&I Stone & Webster, Inc., as contractor, for Units 3&4 at the Vogtle Electric Generating Plant Site.The City of Dalton, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Bechtel Power Corporation. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.) |
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| | | (c) | | 9 | | — | | | Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement dated as of April 21, 2006, among Georgia Power, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, Amendment 1 thereto dated as of April 8, 2008, Amendment 2 thereto dated as of February 20, 2014, and Agreement Regarding Additional Participating Party Rights and Amendment 3 thereto dated as of November 2, 2017. (Designated in Form 8-K dated April 21, 2006, File No. 33-7591, as Exhibit 10.4.4, in Form 10-K for the year ended December 31, 2013, File No. 000-53908, as Exhibit 10.3.2(a), in Form 10-K for the year ended December 31, 2013, File No. 000-53908, as Exhibit 10.3.2(b), and in Form 10-Q for the quarter ended September 30, 2017, File No. 000-53908, as Exhibit 10.1.) |
| | Gulf Power |
| | | (d) | | 1 | | — | | Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS. See Exhibit 10(b)1 herein. |
| | # | (d) | | 2 | | — | | Southern Company 2011 Omnibus Incentive Compensation Plan effective May 25, 2011. See Exhibit 10(a)1 herein. |
| | # | (d) | | 3 | | — | | Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein. |
| | # | (d) | | 4 | | — | | Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)4 herein. |
| | # | (d) | | 5 | | — | | The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)6 herein. |
| | # | (d) | | 6 | | — | | Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)12 herein. |
| | # | (d) | | 7 | | — | | The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective January 1, 2009 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)5 herein. |
| | # | (d) | | 8 | | — | | Deferred Compensation Plan For Outside Directors of Gulf Power Company, Amended and Restated effective January 1, 2008 and First Amendment thereto effective April 1, 2015. (Designated in Gulf Power's Form 10-Q for the quarter ended March 31, 2008, File No. 0-2429, as Exhibit 10(d)1 and in Gulf Power's Form 10-Q for the quarter ended June 30, 2015, File No. 001-11229, as Exhibit 10(d)1.) |
| | # | (d) | | 9 | | — | | The Southern Company Change in Control Benefits Protection Plan (an amendment and restatement of The Southern Company Change in Control Benefit Plan Determination Policy), effective December 31, 2008. See Exhibit 10(a)7 herein. |
| | # | (d) | | 10 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)8 herein. |
| | # | (d) | | 11 | | — | | Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)9 herein. |
| | # | (d) | | 12 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective September 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)10 herein. |
| | # | (d) | | 13 | | — | | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. See Exhibit 10(a)11 herein. |
| | # | (d) | | 14 | | — | | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)13 herein. |
| | # | (d) | | 15 | | — | | Deferred Compensation Agreement between Southern Company, Georgia Power, Gulf Power, and Southern Nuclear and Bentina C. Terry dated August 1, 2010. (Designated in Gulf Power's Form 10-Q for the quarter ended September 30, 2010, File No. 001-31737, as Exhibit 10(d)2.) |
| | # | (d) | | 16 | | — | | Outside Directors Stock Plan for The Southern Company and its Subsidiaries effective June 1, 2015. See Exhibit 10(a)16 herein. |
| | # | (d) | | 17 | | — | | Second Amendment to The Southern Company Supplemental Executive Retirement Plan effective January 2, 2016. See Exhibit 10(a)19 herein. |
| | # | (d) | | 18 | | — | | Second Amendment to The Southern Company Supplemental Benefit Plan effective January 2, 2016. See Exhibit 10(a)20 herein. |
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| | # | (d) | | 19 | | — | | Second Amendment to The Southern Company Deferred Compensation Plan effective October 29, 2014. See Exhibit 10(a)21 herein. |
| | Mississippi Power |
| | | (e) | | 1 | | — | | Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS. See Exhibit 10(b)1 herein. |
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| | | (e) | | 2 | | — | | Transmission Facilities Agreement dated February 25, 1982, Amendment No. 1 dated May 12, 1982 and Amendment No. 2 dated December 6, 1983, between Entergy Corporation (formerly Gulf States) and Mississippi Power. (Designated in Mississippi Power's Form 10-K for the year ended December 31, 1981, File No. 001-11229, as Exhibit 10(f), in Mississippi Power's Form 10-K for the year ended December 31, 1982, File No. 001-11229, as Exhibit 10(f)(2), and in Mississippi Power's Form 10-K for the year ended December 31, 1983, File No. 001-11229, as Exhibit 10(f)(3).) |
| | # | (e) | | 3 | | — | | Southern Company 2011 Omnibus Incentive Compensation Plan effective May 25, 2011. See Exhibit 10(a)1 herein. |
| | # | (e) | | 4 | | — | | Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein. |
| | # | (e) | | 5 | | — | | Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2009 and First Amendment thereto effective January 1, 2010.2018. See Exhibit 10(a)4 herein. |
| | # | (e) | | 6 | | — | | The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. See Exhibit 10(a)6 herein. |
| | # | (e) | | 7 | | — | | Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)12 herein. |
| | # | (e) | | 8 | | — | | The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective JanuaryJune 30, 2016 and Amendment No. 1 2009 and First Amendment thereto effective January 1, 2010.2017. See Exhibit 10(a)5 herein. |
| | # | (e) | | 9 | | — | | |
| | # | (e) | | 10 | | — | | The Southern Company Change in Control Benefits Protection Plan (an amendment and restatement of The Southern Company Change in Control Benefit Plan Determination Policy), effective December 31, 2008. See Exhibit 10(a)7 herein. |
| | # | (e) | | 11 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, SouthernLINC Wireless,Southern Linc, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)8 herein. |
| | # | (e) | | 12 | | — | | Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2000, between Reliance Trust Company, Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)9 herein. |
| | # | (e) | | 13 | | — | | Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective September 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)10 herein. |
| | # | (e) | | 14 | | — | | Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. See Exhibit 10(a)11 herein. |
| | | (e) | | 15 | | — | | Cooperative Agreement between the DOE and SCS dated as of December 12, 2008. (Designated in Mississippi Power's Form 10-K for the year ended December 31, 2008, File No. 001-11229, as Exhibit 10(e)22.22.) (Mississippi Power requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Mississippi Power omitted such portions from this filing and filed them separately with the SEC.) |
|
| | | | | | | | | | |
| | # | (e) | | 16 | | — | | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)13 herein. |
| | # | (e) | | 17 | | — | | Amended Deferred Compensation Agreement effective December 31, 2008 between Southern Company, SCS, Georgia Power, Gulf Power and G. Edison Holland, Jr. (Designated in Form 10-Q for the quarter ended March 31, 2011, File No. 001-11229, as Exhibit 10(a)2.) |
| | # | (e) | | 18 | | — | | Outside Directors Stock Plan for The Southern Company and its Subsidiaries effective June 1, 2015. See Exhibit 10(a)1614 herein. |
| | # | (e) | | 18 | | — | | |
|
| | | | | | | | | | |
| | # | (e) | | 19 | | — | | Second Amendment to The |
| | # | (e) | | 20 | | — | | Second Amendment to The Southern Company Supplemental BenefitExecutive Retirement Plan effective January 2, 2016.1, 2018. See Exhibit 10(a)2016 herein. |
| | # | (e) | | 21 | | — | | Second Amendment to The Southern Company Deferred CompensationSupplemental Benefit Plan effective October 29, 2014.January 1, 2018. See Exhibit 10(a)17 herein. |
| | # | (e) | | 22 | | — | | Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)19 herein. |
| | # | (e) | | 23 | | — | | Form of Time-Vesting Restricted Stock Unit Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)21 herein. |
| | Southern Power |
| | | (f) | | 1 | | — | | Service contract dated as of January 1, 2001, between SCS and Southern Power Company. (Designated in Southern Company's Form 10-K for the year ended December 31, 2001, File No. 1-3526, as Exhibit 10(a)(2).) |
| | | (f) | | 2 | | — | | Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS. See Exhibit 10(b)1 herein. |
| | Southern Company Gas |
| (f) | | (g) | | 1 | | — | | |
| | | (g) | | 3 | | — | | Amended and Restated Engineering, Procurement and Construction |
| | | (g) | | 4 | | — | | Bank Rate Mode Covenants Agreement, dated as of August 31,February 26, 2013 and First Amendment to Bank Rate Mode Covenants Agreement dated as of October 30, 2015. (Southern Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Southern Power omitted such portions from the filing(Designated in Form 8-K dated February 26, 2013, File No. 1-14174, as Exhibit 10.1 and filed them separately with the SEC.)(Designated in Form 10-Q for the quarter ended September8-K dated October 30, 2015, File No. 333-98533,1-14174, as Exhibit 10(e)1.10.3.) |
| | | (g) | | 5 | | — | | |
| | | (g) | | 6 | | — | | |
| | | (g) | | 7 | | — | | |
| | | (g) | | 8 | | — | | |
| | | (g) | | 9 | | — | | |
| | | (g) | | 10 | | — | | Asset Purchase Agreement, dated as of October 15, 2017, by and between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer. (Designated in Form 8-K dated October 15, 2017, File No. 1-14174, as Exhibit 10.1.) |
| | | | | | | | | |
(14) | | Code of Ethics |
| | Southern Company |
| | | (a) | | | | — | | The Southern Company Code of Ethics. (Designated in Southern Company's Form 10-K for the year ended December 31, 2013,2016, File No. 1-3526, as Exhibit 14(a).) |
| | Alabama Power |
| | | (b) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
| | Georgia Power |
| | | (c) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
| | Gulf Power |
| | | (d) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
| | Mississippi Power |
| | | (e) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
| | Southern Power |
| | | (f) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
|
| | | | | | | | | | |
| | Southern Company Gas |
| | | (g) | | | | — | | The Southern Company Code of Ethics. See Exhibit 14(a) herein. |
| | | | | | | | | |
(21) | | Subsidiaries of Registrants |
| | Southern Company |
| | * | (a) | | | | — | | |
| | Alabama Power |
| | | (b) | | | | — | | Subsidiaries of Registrant. See Exhibit 21(a) herein. |
| | Georgia Power |
| | | (c) | | | | — | | SubsidiariesOmitted pursuant to General Instruction I(2)(b) of Registrant. See Exhibit 21(a) herein.Form 10-K. |
| | Gulf Power |
| | | (d) | | | | — | | SubsidiariesOmitted pursuant to General Instruction I(2)(b) of Registrant. See Exhibit 21(a) herein. |
|
| | | | | | | | | | Form 10-K. |
| | Mississippi Power |
| | | (e) | | | | — | | Subsidiaries of Registrant. See Exhibit 21(a) herein. |
| | Southern Power |
| | | Omitted pursuant to General Instruction I(2)(b) of Form 10-K. |
| | Southern Company Gas |
| | | Omitted pursuant to General Instruction I(2)(b) of Form 10-K |
| | | | | | | | | |
(23) | | Consents of Experts and Counsel |
| | Southern Company |
| | * | (a) | | 1 |
| | — | | |
| | Alabama Power |
| | * | (b) | | 1 |
| | — | | |
| | Georgia Power |
| | * | (c) | | 1 |
| | — | | |
| | Gulf Power |
| | * | (d) | | 1 |
| | — | | |
| | Mississippi Power |
| | * | (e) | | 1 |
| | — | | |
| | Southern Power |
| | * | (f) | | 1 |
| | — | | |
| | Southern Company Gas |
| | * | (g) | | 1 |
| | — | | |
| | * | (g) | | 2 |
| | — | | |
| | * | (g) | | 3 |
| | — | | |
| | | | | | | | | |
(24) | | Powers of Attorney and Resolutions |
| | Southern Company |
| | * | (a) | | | | — | | |
| | Alabama Power |
| | * | (b) | | | | — | | |
| | Georgia Power |
| | * | (c) | | | | — | | |
| | Gulf Power |
| | * | (d) | | | | — | | Power of Attorney and resolution. |
| | Mississippi Power |
| | * | (e) | | 1 |
| | — | | Power of Attorney and resolution. |
| | * | (e) | | 2 |
| | — | | Power of Attorney for Anthony L. Wilson. |
| | Southern Power |
| | * | (f) | | 1 |
| | — | | Power of Attorney and resolution. |
| | * | (f) | | 2 |
| | — | | Power of Attorney for Joseph A. Miller. |
(31) | | Section 302 Certifications |
| | Southern Company |
| | * | (a) | | 1 | | — | | Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | * | (a) | | 2 | | — | | Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | Alabama Power |
| | * | (b) | | 1 | | — | | Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | * | (b) | | 2 | | — | | Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | Georgia Power |
| | * | (c) | | 1 | | — | | Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | * | (c) | | 2 | | — | | Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
|
| | | | | | | | | | |
| | Gulf Power |
| | * | (d) | | | | — | | |
| | Mississippi Power |
| | * | (e) | | | | — | | |
| | Southern Power |
| | * | (f) | | | | — | | |
| | Southern Company Gas |
| | * | (g) | | | | — | | |
| | | | | | | | | |
(31) | | Section 302 Certifications |
| | Southern Company |
| | * | (a) | | 1 | | — | | |
| | * | (a) | | 2 | | — | | |
| | Alabama Power |
| | * | (b) | | 1 | | — | | |
| | * | (b) | | 2 | | — | | |
| | Georgia Power |
| | * | (c) | | 1 | | — | | |
| | * | (c) | | 2 | | — | | |
| | Gulf Power |
| | * | (d) | | 1 | | — | | |
| | * | (d) | | 2 | | — | | |
| | Mississippi Power |
| | * | (e) | | 1 | | — | | |
| | * | (e) | | 2 | | — | | |
| | Southern Power |
| | * | (f) | | 1 | | — | | |
| | * | (f) | | 2 | | — | | |
| | Southern Company Gas |
| | * | (g) | | 1 | | — | | |
| | * | (g) | | 2 | | — | | |
| | | | | | | | | |
(32) | | Section 906 Certifications |
| | Southern Company |
| | * | (a) | | | | — | | |
| | Alabama Power |
| | * | (b) | | | | — | | |
|
| | | | | | | | | | |
| | Georgia Power |
| | * | (c) | | | | — | | |
| | Gulf Power |
| | * | (d) | | | | — | | |
| | Mississippi Power |
| | * | (e) | | | | — | | |
| | Southern Power |
| | * | (f) | | | | — | | |
| | Southern Company Gas |
| | * | (g) | | | | — | | |
| | | | | | | | | |
(99) | | Additional Exhibits |
| | Southern Company Gas |
| | * | (g) | | | | — | | |
| | | | | | | | | |
(101) | XBRL-Related Documents |
| | * | INS | | | — | | XBRL Instance Document |
| | * | SCH | | | — | | XBRL Taxonomy Extension Schema Document |
| | * | CAL | | | — | | XBRL Taxonomy Calculation Linkbase Document |
| | * | DEF | | | — | | XBRL Definition Linkbase Document |
| | * | LAB | | | — | | XBRL Taxonomy Label Linkbase Document |
| | * | PRE | | | — | | XBRL Taxonomy Presentation Linkbase Document |
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
THE SOUTHERN COMPANY |
| |
By: | Thomas A. Fanning |
| Chairman, President, and |
| Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Thomas A. Fanning Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Art P. Beattie Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | | |
| | | |
Ann P. Daiss Comptroller and Chief Accounting Officer (Principal Accounting Officer) | | | |
Directors: | | |
Juanita Powell Baranco Jon A. Boscia Henry A. Clark III David J. Grain Veronica M. Hagen Warren A. Hood, Jr. Linda P. Hudson
| Donald M. James John D. Johns Dale E. Klein William G. Smith, Jr. Steven R. Specker Larry D. Thompson E. Jenner Wood III
| | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
ALABAMA POWER COMPANY |
| |
By: | Mark A. Crosswhite |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Mark A. Crosswhite Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Philip C. Raymond Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) | | | |
| | | |
Anita Allcorn-Walker Vice President and Comptroller (Principal Accounting Officer) | | | |
Directors: | | |
Whit Armstrong David J. Cooper, Sr. O. B. Grayson Hall, Jr. Anthony A. Joseph Patricia M. King
| James K. Lowder Robert D. Powers Catherine J. Randall C. Dowd Ritter R. Mitchell Shackleford, III | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
GEORGIA POWER COMPANY |
| |
By: | W. Paul Bowers |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
W. Paul Bowers Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Xia Liu Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) | | | |
| | | |
David P. Poroch Comptroller and Vice President (Principal Accounting Officer) | | | |
Directors: | | |
Mark L. Burns Shantella E. Cooper Lawrence L. Gellerstedt III Stephen S. Green Douglas J. Hertz | Kessel D. Stelling, Jr. Jimmy C. Tallent Charles K. Tarbutton Beverly Daniel Tatum Clyde C. Tuggle | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
GULF POWER COMPANY |
| |
By: | S. W. Connally, Jr. |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
S. W. Connally, Jr. Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Robin B. Boren Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) | | | |
| | | |
Paul D. Trippe Comptroller (Principal Accounting Officer) | | | |
Directors: | | |
Allan G. Bense | J. Mort O'Sullivan, III | | |
Deborah H. Calder | Michael T. Rehwinkel | | |
William C. Cramer, Jr. | Winston E. Scott | | |
Julian B. MacQueen | | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:
Gulf Power Company is not required to send an annual report or proxy statement to its sole shareholder and parent company, The Southern Company, and will not prepare such a report after filing this Annual Report on Form 10-K for fiscal year 2017. Accordingly, Gulf Power Company will not file an annual report with the Securities and Exchange Commission.
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
MISSISSIPPI POWER COMPANY |
| |
By: | Anthony L. Wilson |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Anthony L. Wilson Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Moses H. Feagin Vice President, Treasurer, and Chief Financial Officer (Principal Financial Officer) | | | |
| | | |
Cynthia F. Shaw Comptroller (Principal Accounting Officer) | | | |
Directors: | | |
Carl J. Chaney | Christine L. Pickering | | |
L. Royce Cumbest | Phillip J. Terrell | | |
Mark E. Keenum | M.L. Waters | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
SOUTHERN POWER COMPANY |
| |
By: | Joseph A. Miller |
| Chairman, President and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Joseph A. Miller Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
William C. Grantham Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) | | | |
| | | |
Elliott L. Spencer Comptroller and Corporate Secretary (Principal Accounting Officer) | | | |
Directors: | | |
Art P. Beattie | James Y. Kerr, II | | |
Thomas A. Fanning | Mark S. Lantrip | | |
Kimberly S. Greene | Christopher C. Womack | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
SOUTHERN COMPANY GAS
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
|
| |
SOUTHERN COMPANY GAS |
| |
By: | Andrew W. Evans |
| Chairman, President, and Chief Executive Officer |
| |
By: | /s/Melissa K. Caen |
| (Melissa K. Caen, Attorney-in-fact) |
| |
Date: | February 20, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
|
| | | |
Andrew W. Evans Chairman, President, and Chief Executive Officer (Principal Executive Officer) | | | |
| | | |
Elizabeth W. Reese Executive Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer) | | | |
| | | |
Grace A. Kolvereid Senior Vice President and Comptroller (Principal Accounting Officer) | | | |
Directors: | | |
Sandra N. Bane | Kimberly S. Greene | | |
Thomas D. Bell, Jr. | John E. Rau | | |
Charles R. Crisp | James A. Rubright | | |
Brenda J. Gaines | | | |
|
| | |
By: | | /s/Melissa K. Caen |
| | (Melissa K. Caen, Attorney-in-fact) |
Date: February 20, 2018
Supplemental Information to be Furnished with Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act:
Southern Company Gas is not required to send an annual report or proxy statement to its sole shareholder and parent company, The Southern Company, and will not prepare such a report after filing this Annual Report on Form 10-K for fiscal year 2017. Accordingly, Southern Company Gas will not file an annual report with the Securities and Exchange Commission.