UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2016March 31, 2017
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 (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 | | 58-0690070 |
| | | | | |
| 1-3164 | | Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35203 (205) 257-1000 | | 63-0004250 |
| | | | | |
| 1-6468 | | Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526 | | 58-0257110 |
| | | | | |
| 001-31737 | | Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111 | | 59-0276810 |
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| 001-11229 | | Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211 | | 64-0205820 |
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| 001-37803 | | Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 | | 58-2598670 |
| | | | |
| 1-14174 | | Southern Company Gas
(A Georgia Corporation)
Ten Peachtree Place, N.E. Atlanta, Georgia 30309
(404) 584-4000 | | 58-2210952 |
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 þ 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 þ No ¨
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 þ (Response applicable to all registrants.)
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| | | | | |
| Registrant | | Description of Common Stock | | Shares Outstanding at September 30, 2016March 31, 2017 |
|
| The Southern Company | | Par Value $5 Per Share | | 979,999,480994,598,783 |
|
| Alabama Power Company | | Par Value $40 Per Share | | 30,537,500 |
|
| Georgia Power Company | | Without Par Value | | 9,261,500 |
|
| Gulf Power Company | | Without Par Value | | 5,642,7177,392,717 |
|
| Mississippi Power Company | | Without Par Value | | 1,121,000 |
|
| Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
|
| Southern Company Gas | | Par Value $0.01 Per Share | | 100 |
|
This combined Form 10-Q 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 registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2016March 31, 2017
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| | PART I—FINANCIAL INFORMATION | |
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| Item 1. | Financial Statements (Unaudited) | |
| Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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Item 3. | | |
Item 4. | | |
INDEX TO QUARTERLY REPORT ON FORM 10-Q
September 30, 2016March 31, 2017
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Number |
| PART I—FINANCIAL INFORMATION (CONTINUED) | |
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| Item 3. | | |
| Item 4. | | |
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| Item 1. | | |
| Item 1A. | | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | Inapplicable |
| Item 3. | Defaults Upon Senior Securities | Inapplicable |
| Item 4. | Mine Safety Disclosures | Inapplicable |
| Item 5. | | Inapplicable |
| Item 6. | | |
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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 the acquisition, construction, and operation of the Kemper IGCC |
| 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 |
| ASC | Accounting Standards Codification |
| ASU | Accounting Standards Update |
| Atlanta Gas Light | Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas |
| Baseload Act | State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi |
Bridge Agreement | Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A. |
| CCR | Coal combustion residuals |
| Clean Power Plan | Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units |
CO2 | Carbon dioxide |
| COD | Commercial operation date |
| 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. |
| CPCN | Certificate of public convenience and necessity |
| CWIP | Construction work in progress |
| Dalton Pipeline | A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia |
| DOE | U.S. Department of Energy |
| ECO Plan | Mississippi Power's Environmental Compliance Overview Plan |
| Eligible Project Costs | Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program |
| EPA | U.S. Environmental Protection Agency |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FFB | Federal Financing Bank |
| Fitch | Fitch Ratings, Inc. |
| Form 10-K | Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas for the year ended December 31, 20152016, as applicable |
| GAAP | U.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| Gulf Power | Gulf Power Company |
| Heating Degree Days | A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit |
| Horizon Pipeline | Horizon Pipeline Company, LLC |
| IGCC | Integrated coal gasification combined cycle |
| IIC | Intercompany interchange contract |
| Illinois Commission | Illinois Commerce Commission, the state regulatory agency for Nicor Gas |
| Internal Revenue Code | Internal Revenue Code of 1986, as amended |
| IRS | Internal Revenue Service |
| ITC | Investment tax credit |
| Kemper IGCC | IGCC facility under construction by Mississippi Power in Kemper County, Mississippi |
DEFINITIONS
(continued)
|
| |
| Term | Meaning |
| |
| KWH | Kilowatt-hour |
| LIBOR | London Interbank Offered Rate |
| LIFO | Last-in, first-out |
| LNG | Liquefied natural gas |
| LOCOM | Lower of weighted average cost or current market price |
| LTSA | Long-term service agreement |
| MATS rule | Mercury and Air Toxics Standards rule |
| 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 customer refunds resulting from a 2015 Mississippi PSC order |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| |
| Mississippi Power | Mississippi Power Company |
| mmBtu | Million British thermal units |
| Moody's | Moody's Investors Service, Inc. |
| MRA | Municipal and Rural Associations |
| MW | Megawatt |
| 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 Company, and Elkton Gas) |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
| 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 |
| Nicor Gas Credit Facility | $700 million credit facility entered into by Nicor Gas to support its commercial paper program |
| NRC | U.S. Nuclear Regulatory Commission |
| NYMEX | New York Mercantile Exchange, Inc. |
| OCI | Other comprehensive income |
PATH ActPennEast Pipeline | The Protecting Americans from Tax Hikes ActPennEast Pipeline Company, LLC |
| PEP | Mississippi Power's Performance Evaluation Plan |
| 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 |
| Plant Vogtle Units 3 and 4 | Two new nuclear generating units under construction at Georgia Power's Plant Vogtle |
| PowerSecure | PowerSecure, 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 agreements, andas well as, for Southern Power, contracts for differences that provide the owner of thea 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 |
DEFINITIONS
(continued)
|
| |
| Term | Meaning |
| |
| 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 |
| registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company, and Southern Company Gas |
| ROE | Return on equity |
| S&P | S&P Global Ratings, a division of 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 |
| SMEPA | South Mississippi Electric Power Association (now known as Cooperative Energy) |
| SNG | Southern Natural Gas Company, L.L.C. |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries |
| Southern Company Gas Capital | Southern Company Gas Capital Corporation, a wholly-owned100%-owned subsidiary of Southern Company Gas |
| Southern Company Gas Credit Facility | $1.3 billion credit agreement entered into by Southern Company Gas Capital to support its commercial paper program |
| 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 Communications Services, Inc., PowerSecure (as of May 9, 2016), and other subsidiaries and, as of July 1, 2016, Southern Company Gas |
| 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 |
| Toshiba | Toshiba Corporation, parent company of Westinghouse |
| Toshiba Guarantee | Certain payment obligations of the Contractor guaranteed by Toshiba |
| traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
| Triton | Triton Container Investments, LLC |
| Virginia Commission | Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas |
| Virginia Natural Gas | Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas |
| 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 |
| WACOG | Weighted average cost of gas |
| WECTEC | WECTEC Global Project Services Inc. |
| Westinghouse | Westinghouse Electric Company LLC |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the wholesale business, 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, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, 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 utility industry, environmental laws regulating emissions, discharges, and disposal to air, water, and land, 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;
current and future litigation, regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;
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;
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, sustaining nitrogen supply, 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);
the ability to construct facilities in accordance with the requirements of permits and licenses, 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 Southern Company's employee and retiree benefit plans and the Southern Company system's 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;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
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;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q 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, financing activities, completion dates of construction projects, filings with state and federal regulatory authorities, 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 regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;
current and future litigation, 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 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;
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 finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, 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);
the results of the Contractor's bankruptcy filing and the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4, as well as the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 and Georgia Power's DOE loan guarantees;
the ability to construct facilities in accordance with the requirements of permits and licenses, 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;
legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)
actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court 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;
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, 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, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;
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 incidents and the threat of terrorist incidents;
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;
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 registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.
THE SOUTHERN COMPANY
AND SUBSIDIARY COMPANIES
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Retail electric revenues | $ | 4,808 |
| | $ | 4,701 |
| | $ | 11,932 |
| | $ | 11,958 |
| $ | 3,394 |
| | $ | 3,377 |
|
| Wholesale electric revenues | 613 |
| | 520 |
| | 1,455 |
| | 1,435 |
| 531 |
| | 396 |
|
| Other electric revenues | 181 |
| | 169 |
| | 529 |
| | 494 |
| 175 |
| | 181 |
|
| Natural gas revenues | 518 |
| | — |
| | 518 |
| | — |
| 1,530 |
| | — |
|
| Other revenues | 144 |
| | 11 |
| | 281 |
| | 34 |
| 141 |
| | 38 |
|
| Total operating revenues | 6,264 |
| | 5,401 |
| | 14,715 |
| | 13,921 |
| 5,771 |
| | 3,992 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 1,400 |
| | 1,520 |
| | 3,334 |
| | 3,932 |
| 996 |
| | 911 |
|
| Purchased power | 227 |
| | 193 |
| | 581 |
| | 507 |
| 179 |
| | 165 |
|
| Cost of natural gas | 133 |
| | — |
| | 133 |
| | — |
| 719 |
| | — |
|
| Cost of other sales | 84 |
| | — |
| | 161 |
| | — |
| 88 |
| | 19 |
|
| Other operations and maintenance | 1,411 |
| | 1,097 |
| | 3,616 |
| | 3,320 |
| 1,329 |
| | 1,107 |
|
| Depreciation and amortization | 695 |
| | 528 |
| | 1,805 |
| | 1,515 |
| 716 |
| | 541 |
|
| Taxes other than income taxes | 309 |
| | 264 |
| | 821 |
| | 761 |
| 330 |
| | 256 |
|
| Estimated loss on Kemper IGCC | 88 |
| | 150 |
| | 222 |
| | 182 |
| 108 |
| | 53 |
|
| Total operating expenses | 4,347 |
| | 3,752 |
| | 10,673 |
| | 10,217 |
| 4,465 |
| | 3,052 |
|
| Operating Income | 1,917 |
| | 1,649 |
| | 4,042 |
| | 3,704 |
| 1,306 |
| | 940 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Allowance for equity funds used during construction | 52 |
| | 60 |
| | 150 |
| | 163 |
| 57 |
| | 53 |
|
| Earnings from equity method investments | | 39 |
| | — |
|
| Interest expense, net of amounts capitalized | (374 | ) | | (218 | ) | | (913 | ) | | (612 | ) | (416 | ) | | (246 | ) |
| Other income (expense), net | 21 |
| | (21 | ) | | (38 | ) | | (41 | ) | (6 | ) | | (29 | ) |
| Total other income and (expense) | (301 | ) | | (179 | ) | | (801 | ) | | (490 | ) | (326 | ) | | (222 | ) |
| Earnings Before Income Taxes | 1,616 |
| | 1,470 |
| | 3,241 |
| | 3,214 |
| 980 |
| | 718 |
|
| Income taxes | 448 |
| | 500 |
| | 942 |
| | 1,076 |
| 315 |
| | 217 |
|
| Consolidated Net Income | 1,168 |
| | 970 |
| | 2,299 |
| | 2,138 |
| 665 |
| | 501 |
|
| Less: | | | | | | | | | | |
| Dividends on Preferred and Preference Stock of Subsidiaries | 11 |
| | 11 |
| | 34 |
| | 42 |
| |
| Net income attributable to noncontrolling interests | 27 |
| | — |
| | 39 |
| | — |
| |
| Dividends on preferred and preference stock of subsidiaries | | 11 |
| | 11 |
|
| Net income (loss) attributable to noncontrolling interests | | (4 | ) | | 1 |
|
| Consolidated Net Income Attributable to Southern Company | $ | 1,130 |
| | $ | 959 |
| | $ | 2,226 |
| | $ | 2,096 |
| $ | 658 |
| | $ | 489 |
|
| Common Stock Data: | | | | | | | | | | |
| Earnings per share (EPS) — | | | | | | | | | | |
| Basic EPS | $ | 1.17 |
| | $ | 1.05 |
| | $ | 2.37 |
| | $ | 2.30 |
| $ | 0.66 |
| | $ | 0.53 |
|
| Diluted EPS | $ | 1.16 |
| | $ | 1.05 |
| | $ | 2.36 |
| | $ | 2.30 |
| $ | 0.66 |
| | $ | 0.53 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | |
| Basic | 968 |
| | 910 |
| | 940 |
| | 910 |
| 993 |
| | 916 |
|
| Diluted | 975 |
| | 912 |
| | 945 |
| | 913 |
| 1,000 |
| | 922 |
|
| Cash dividends paid per share of common stock | $ | 0.5600 |
| | $ | 0.5425 |
| | $ | 1.6625 |
| | $ | 1.6100 |
| $ | 0.5600 |
| | $ | 0.5425 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Consolidated Net Income | $ | 1,168 |
| | $ | 970 |
| | $ | 2,299 |
| | $ | 2,138 |
| $ | 665 |
| | $ | 501 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $12, $(11), $(74), and $(10),
respectively | 19 |
| | (18 | ) | | (118 | ) | | (16 | ) | |
Reclassification adjustment for amounts included in net income,
net of tax of $2, $1, $13, and $3, respectively | 2 |
| | 1 |
| | 20 |
| | 4 |
| |
| Pension and other postretirement benefit plans: | | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $3, respectively | 1 |
| | 2 |
| | 3 |
| | 5 |
| |
| Changes in fair value, net of tax of $(5) and $(72), respectively | | (9 | ) | | (117 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $(1) and $1, respectively | | (1 | ) | | 2 |
|
| Pension and other post retirement benefit plans: | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $- and $1, respectively | | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 22 |
| | (15 | ) | | (95 | ) | | (7 | ) | (9 | ) | | (114 | ) |
| Less: | | | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | 11 |
| | 11 |
| | 34 |
| | 42 |
| 11 |
| | 11 |
|
| Comprehensive income attributable to noncontrolling interests | 27 |
| | — |
| | 39 |
| | — |
| |
| Comprehensive income (loss) attributable to noncontrolling interests | | (4 | ) | | 1 |
|
Consolidated Comprehensive Income Attributable to Southern Company | $ | 1,152 |
| | $ | 944 |
| | $ | 2,131 |
| | $ | 2,089 |
| $ | 649 |
| | $ | 375 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Consolidated net income | $ | 2,299 |
| | $ | 2,138 |
| $ | 665 |
| | $ | 501 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 2,109 |
| | 1,787 |
| 823 |
| | 639 |
|
| Deferred income taxes | (22 | ) | | 821 |
| 161 |
| | (4 | ) |
| Investment tax credits | — |
| | 319 |
| |
| Allowance for equity funds used during construction | (150 | ) | | (163 | ) | (57 | ) | | (53 | ) |
| Pension, postretirement, and other employee benefits | (158 | ) | | 79 |
| |
| Settlement of asset retirement obligations | (117 | ) | | (20 | ) | |
| Stock based compensation expense | 87 |
| | 77 |
| 61 |
| | 58 |
|
| Hedge settlements | (236 | ) | | (4 | ) | |
| Estimated loss on Kemper IGCC | 222 |
| | 182 |
| 108 |
| | 53 |
|
| Income taxes receivable, non-current | — |
| | (444 | ) | |
| Mark-to-market adjustments | | (81 | ) | | (2 | ) |
| Other, net | (98 | ) | | (48 | ) | (11 | ) | | (6 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (458 | ) | | (118 | ) | 312 |
| | 235 |
|
| -Fossil fuel for generation | 204 |
| | 239 |
| |
| -Natural gas for sale | (222 | ) | | — |
| |
| -Prepayments | | (111 | ) | | (65 | ) |
| -Natural gas for sale, net of temporary LIFO liquidation | | 411 |
| | — |
|
| -Other current assets | (111 | ) | | (40 | ) | (31 | ) | | (7 | ) |
| -Accounts payable | (9 | ) | | (266 | ) | (533 | ) | | (72 | ) |
| -Accrued taxes | 1,062 |
| | 408 |
| (212 | ) | | (57 | ) |
| -Accrued compensation | (122 | ) | | (129 | ) | (438 | ) | | (332 | ) |
| -Mirror CWIP | — |
| | 99 |
| |
| -Retail fuel cost over recovery | | (122 | ) | | 25 |
|
| -Other current liabilities | (18 | ) | | 171 |
| (48 | ) | | (35 | ) |
| Net cash provided from operating activities | 4,262 |
| | 5,088 |
| 897 |
| | 878 |
|
| Investing Activities: | | | | | | |
| Business acquisitions, net of cash acquired | (9,513 | ) | | (1,128 | ) | (1,020 | ) | | (114 | ) |
| Property additions | (5,252 | ) | | (3,490 | ) | (1,488 | ) | | (1,872 | ) |
| Investment in restricted cash | (750 | ) | | — |
| (13 | ) | | (289 | ) |
| Distribution of restricted cash | 746 |
| | — |
| 26 |
| | 292 |
|
| Nuclear decommissioning trust fund purchases | (838 | ) | | (1,164 | ) | (224 | ) | | (316 | ) |
| Nuclear decommissioning trust fund sales | 832 |
| | 1,159 |
| 218 |
| | 311 |
|
| Cost of removal, net of salvage | (155 | ) | | (118 | ) | (61 | ) | | (52 | ) |
| Change in construction payables, net | (259 | ) | | 20 |
| (170 | ) | | (94 | ) |
| Investment in unconsolidated subsidiaries | (1,421 | ) | | — |
| (81 | ) | | — |
|
| Prepaid long-term service agreement | (125 | ) | | (166 | ) | |
| Payments pursuant to LTSAs | | (55 | ) | | (49 | ) |
| Other investing activities | 95 |
| | 7 |
| 65 |
| | (14 | ) |
| Net cash used for investing activities | (16,640 | ) | | (4,880 | ) | (2,803 | ) | | (2,197 | ) |
| Financing Activities: | | | | | | |
| Increase in notes payable, net | 655 |
| | 662 |
| 573 |
| | 294 |
|
| Proceeds — | | | | | | |
| Long-term debt | 14,091 |
| | 3,992 |
| 1,409 |
| | 1,997 |
|
| Common stock | 3,265 |
| | 136 |
| 186 |
| | 270 |
|
| Short-term borrowings | — |
| | 280 |
| 4 |
| | — |
|
| Redemptions and repurchases — | | | | | | |
| Long-term debt | (2,405 | ) | | (2,562 | ) | (608 | ) | | (888 | ) |
| Interest-bearing refundable deposits | — |
| | (275 | ) | |
| Preferred and preference stock | — |
| | (412 | ) | |
| Common stock | — |
| | (115 | ) | |
| Short-term borrowings | (475 | ) | | (255 | ) | — |
| | (475 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) | (18 | ) | | (4 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
| 71 |
| | 131 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
| — |
| | (129 | ) |
| Payment of common stock dividends | (1,553 | ) | | (1,465 | ) | (556 | ) | | (497 | ) |
| Other financing activities | (151 | ) | | (63 | ) | (36 | ) | | (30 | ) |
| Net cash provided from financing activities | 13,643 |
| | 191 |
| 1,025 |
| | 669 |
|
| Net Change in Cash and Cash Equivalents | 1,265 |
| | 399 |
| (881 | ) | | (650 | ) |
| Cash and Cash Equivalents at Beginning of Period | 1,404 |
| | 710 |
| 1,975 |
| | 1,404 |
|
| Cash and Cash Equivalents at End of Period | $ | 2,669 |
| | $ | 1,109 |
| $ | 1,094 |
| | $ | 754 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $94 and $88 capitalized for 2016 and 2015, respectively) | $ | 766 |
| | $ | 590 |
| |
| Interest (net of $25 and $30 capitalized for 2017 and 2016, respectively) | | $ | 461 |
| | $ | 224 |
|
| Income taxes, net | (151 | ) | | (13 | ) | (6 | ) | | (141 | ) |
| Noncash transactions — Accrued property additions at end of period | 578 |
| | 483 |
| 578 |
| | 731 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 2,669 |
| | $ | 1,404 |
| | $ | 1,094 |
| | $ | 1,975 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 1,718 |
| | 1,058 |
| | 1,560 |
| | 1,565 |
|
| Energy marketing receivable | | 526 |
| | — |
| | 493 |
| | 623 |
|
| Unbilled revenues | | 639 |
| | 397 |
| | 589 |
| | 706 |
|
| Under recovered regulatory clause revenues | | 54 |
| | 63 |
| | 47 |
| | 18 |
|
| Income taxes receivable, current | | — |
| | 144 |
| | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 317 |
| | 398 |
| | 433 |
| | 377 |
|
| Accumulated provision for uncollectible accounts | | (43 | ) | | (13 | ) | | (53 | ) | | (43 | ) |
| Materials and supplies | | 1,268 |
| | 1,061 |
| | 1,477 |
| | 1,462 |
|
| Fossil fuel for generation | | 664 |
| | 868 |
| | 687 |
| | 689 |
|
| Natural gas for sale | | 627 |
| | — |
| | 346 |
| | 631 |
|
| Vacation pay | | 178 |
| | 178 |
| |
| Prepaid expenses | | 459 |
| | 495 |
| | 401 |
| | 364 |
|
| Other regulatory assets, current | | 414 |
| | 402 |
| | 560 |
| | 581 |
|
| Other current assets | | 168 |
| | 71 |
| | 249 |
| | 230 |
|
| Total current assets | | 9,658 |
| | 6,526 |
| | 8,427 |
| | 9,722 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 94,174 |
| | 75,118 |
| | 99,774 |
| | 98,416 |
|
| Less accumulated depreciation | | 29,590 |
| | 24,253 |
| |
| Less: Accumulated depreciation | | | 30,330 |
| | 29,852 |
|
| Plant in service, net of depreciation | | 64,584 |
| | 50,865 |
| | 69,444 |
| | 68,564 |
|
| Other utility plant, net | | — |
| | 233 |
| |
| Nuclear fuel, at amortized cost | | 901 |
| | 934 |
| | 902 |
| | 905 |
|
| Construction work in progress | | 10,069 |
| | 9,082 |
| | 9,465 |
| | 8,977 |
|
| Total property, plant, and equipment | | 75,554 |
| | 61,114 |
| | 79,811 |
| | 78,446 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 6,223 |
| | 2 |
| | 6,251 |
| | 6,251 |
|
| Equity investments in unconsolidated subsidiaries | | 1,541 |
| | 6 |
| | 1,615 |
| | 1,549 |
|
Other intangible assets, net of amortization of $39 and $12
at September 30, 2016 and December 31, 2015, respectively | | 942 |
| | 317 |
| |
Other intangible assets, net of amortization of $97 and $62
at March 31, 2017 and December 31, 2016, respectively | | | 935 |
| | 970 |
|
| Nuclear decommissioning trusts, at fair value | | 1,616 |
| | 1,512 |
| | 1,678 |
| | 1,606 |
|
| Leveraged leases | | 769 |
| | 755 |
| | 780 |
| | 774 |
|
| Miscellaneous property and investments | | 249 |
| | 160 |
| | 293 |
| | 270 |
|
| Total other property and investments | | 11,340 |
| | 2,752 |
| | 11,552 |
| | 11,420 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 1,590 |
| | 1,560 |
| | 1,647 |
| | 1,629 |
|
| Unamortized loss on reacquired debt | | 228 |
| | 227 |
| | 218 |
| | 223 |
|
| Other regulatory assets, deferred | | 6,446 |
| | 4,989 |
| | 6,748 |
| | 6,851 |
|
| Income taxes receivable, non-current | | 413 |
| | 413 |
| |
| Other deferred charges and assets | | 1,133 |
| | 737 |
| | 1,357 |
| | 1,406 |
|
| Total deferred charges and other assets | | 9,810 |
| | 7,926 |
| | 9,970 |
| | 10,109 |
|
| Total Assets | | $ | 106,362 |
| | $ | 78,318 |
| | $ | 109,760 |
| | $ | 109,697 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 2,254 |
| | $ | 2,674 |
| | $ | 3,269 |
| | $ | 2,587 |
|
| Notes payable | | 1,670 |
| | 1,376 |
| | 2,818 |
| | 2,241 |
|
| Energy marketing trade payables | | 533 |
| | — |
| | 471 |
| | 597 |
|
| Accounts payable | | 1,732 |
| | 1,905 |
| | 1,750 |
| | 2,228 |
|
| Customer deposits | | 577 |
| | 404 |
| | 541 |
| | 558 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 375 |
| | 19 |
| | 258 |
| | 193 |
|
| Unrecognized tax benefits | | | 400 |
| | 385 |
|
| Other accrued taxes | | 641 |
| | 484 |
| | 326 |
| | 667 |
|
| Accrued interest | | 410 |
| | 249 |
| | 453 |
| | 518 |
|
| Accrued vacation pay | | 231 |
| | 228 |
| |
| Accrued compensation | | 505 |
| | 549 |
| | 461 |
| | 915 |
|
| Asset retirement obligations, current | | 390 |
| | 217 |
| | 386 |
| | 378 |
|
| Liabilities from risk management activities, net of collateral | | 125 |
| | 156 |
| | 63 |
| | 107 |
|
| Acquisitions payable | | | — |
| | 489 |
|
| Other regulatory liabilities, current | | 99 |
| | 278 |
| | 221 |
| | 236 |
|
| Mandatorily redeemable noncontrolling interest | | 174 |
| | — |
| |
| Other current liabilities | | 851 |
| | 590 |
| | 867 |
| | 818 |
|
| Total current liabilities | | 10,567 |
| | 9,129 |
| | 12,284 |
| | 12,917 |
|
| Long-term Debt | | 41,550 |
| | 24,688 |
| | 42,786 |
| | 42,629 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 14,218 |
| | 12,322 |
| | 14,307 |
| | 14,092 |
|
| Deferred credits related to income taxes | | 204 |
| | 187 |
| | 215 |
| | 219 |
|
| Accumulated deferred investment tax credits | | 1,721 |
| | 1,219 |
| | 2,264 |
| | 2,228 |
|
| Employee benefit obligations | | 3,022 |
| | 2,582 |
| | 2,234 |
| | 2,299 |
|
| Asset retirement obligations, deferred | | 4,124 |
| | 3,542 |
| | 4,170 |
| | 4,136 |
|
| Unrecognized tax benefits | | 381 |
| | 370 |
| |
| Accrued environmental remediation | | 415 |
| | 42 |
| | 388 |
| | 397 |
|
| Other cost of removal obligations | | 2,771 |
| | 1,162 |
| | 2,724 |
| | 2,748 |
|
| Other regulatory liabilities, deferred | | 401 |
| | 254 |
| | 237 |
| | 258 |
|
| Other deferred credits and liabilities | | 641 |
| | 678 |
| | 873 |
| | 880 |
|
| Total deferred credits and other liabilities | | 27,898 |
| | 22,358 |
| | 27,412 |
| | 27,257 |
|
| Total Liabilities | | 80,015 |
| | 56,175 |
| | 82,482 |
| | 82,803 |
|
| Redeemable Preferred Stock of Subsidiaries | | 118 |
| | 118 |
| | 118 |
| | 118 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
| | 164 |
| | 164 |
|
| Stockholders' Equity: | | | | | | | | |
| Common Stockholders' Equity: | | | | | | | | |
| Common stock, par value $5 per share — | | | | | | | | |
| Authorized — 1.5 billion shares | | | | | | | | |
| Issued — September 30, 2016: 981 million shares | | | | | |
| — December 31, 2015: 915 million shares | | | | | |
| Treasury — September 30, 2016: 0.8 million shares | | | | | |
| — December 31, 2015: 3.4 million shares | | | | | |
| Issued — March 31, 2017: 995 million shares | | | | | |
| — December 31, 2016: 991 million shares | | | | | |
| Treasury — March 31, 2017: 0.9 million shares | | | | | |
| — December 31, 2016: 0.8 million shares | | | | | |
| Par value | | 4,900 |
| | 4,572 |
| | 4,973 |
| | 4,952 |
|
| Paid-in capital | | 9,217 |
| | 6,282 |
| | 9,884 |
| | 9,661 |
|
| Treasury, at cost | | (30 | ) | | (142 | ) | | (33 | ) | | (31 | ) |
| Retained earnings | | 10,685 |
| | 10,010 |
| | 10,459 |
| | 10,356 |
|
| Accumulated other comprehensive loss | | (225 | ) | | (130 | ) | | (189 | ) | | (180 | ) |
| Total Common Stockholders' Equity | | 24,547 |
| | 20,592 |
| | 25,094 |
| | 24,758 |
|
| Preferred and Preference Stock of Subsidiaries | | 609 |
| | 609 |
| | 609 |
| | 609 |
|
| Noncontrolling Interests | | 1,024 |
| | 781 |
| | 1,293 |
| | 1,245 |
|
| Total Stockholders' Equity | | 26,180 |
| | 21,982 |
| | 26,996 |
| | 26,612 |
|
| Total Liabilities and Stockholders' Equity | | $ | 106,362 |
| | $ | 78,318 |
| | $ | 109,760 |
| | $ | 109,697 |
|
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and of the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional electric operating companies and Southern Power and following the closing of the Merger on July 1, 2016, the distribution of natural gas by Southern Company Gas, formerly known as AGL Resources Inc.Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power 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 is an energy services holding company whose primary business is the distribution ofdistributes natural gas through seven 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 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 in the areas of distributed generation, energy efficiency, and utility infrastructure, as well asservices. Other business activities also include investments in telecommunications, and leveraged lease projects.projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K.
Merger with Southern Company Gas
On July 1, 2016, Southern Company completed the Merger for a total purchase pricecontinues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of approximately $8.0 billionmajor construction projects, and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.earnings per share.
Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The discussion and analysis of results of operations and financial condition set forth herein include Southern Company Gas' results of operations since July 1, 2016 and financial condition as of September 30, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See RISK FACTORS in Item 1A herein for additional information related to the various risks related to the Merger.
Construction Program
Construction continues on 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 582-MW Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.information regarding the construction program. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Key Performance Indicators
Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects,On March 29, 2017, Westinghouse and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7WECTEC each filed for bankruptcy protection under Chapter 11 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $171 | | 17.8 | | $130 | | 6.2 |
Consolidated net income attributableU.S. Bankruptcy Code. Also on March 29, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Company was $1.1 billion ($1.17 per share) forNuclear, in the third quarter 2016 compared to $959 million ($1.05 per share) for the third quarter 2015.event Southern Nuclear assumes control over construction management. The increase was primarily the result of an increase in retail electric revenues resulting from warmer weather and base rate increases, a decrease in income taxes primarily from income tax benefits at Southern Power, and lower charges related to revisions of the estimated costsContractor's bankruptcy filing is expected to be incurredhave a material impact on Mississippi Power'sthe construction of the Kemper IGCC, partially offset by increases in interest expense, depreciationcost and amortization, and non-fuel operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Consolidated net income attributable to Southern Company was $2.2 billion ($2.37 per share) for year-to-date 2016 compared to $2.1 billion ($2.30 per share) for the corresponding period in 2015. The increase was primarily the resultschedule of, an increase in retail electric revenues resulting from base rate increases as well as the 2015 correction ofcost recovery for, Plant Vogtle Units 3 and 4 and could have a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power, partially offset by increases in interest expense and depreciation and amortization.
Although several individual income statement line items reflect variances resulting from the Mergermaterial impact on July 1, 2016 and the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net income for the third quarter and year-to-date 2016 was not significantly impacted by these transactions.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Retail Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $107 | | 2.3 | | $(26) | | (0.2) |
In the third quarter 2016, retail electric revenues were $4.8 billioncompared to $4.7 billion for the corresponding period in 2015. For year-to-date 2016, retail electric revenues decreased slightly compared to the corresponding period in 2015.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
RESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $169 | | 34.6 |
Consolidated net income attributable to Southern Company was $658 million ($0.66 per share) for the first quarter 2017 compared to $489 million ($0.53 per share) for the corresponding period in 2016. Consolidated net income increased by $239 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016, and decreased $12 million as a result of a loss at PowerSecure, which was acquired on May 9, 2016. Also contributing to the increase were higher retail electric revenues resulting from increases in non-fuel retail base rates, an increase in renewable energy sales and income tax benefits at Southern Power, and a decrease in non-fuel operations and maintenance expenses. These increases were partially offset by a decrease in retail electric revenues resulting from milder weather, higher interest expense, higher depreciation and amortization, and higher charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in the first quarter 2017 compared to the corresponding period in 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
Retail Electric Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $17 | | 0.5 |
In the first quarter 2017, retail electric revenues were $3.39 billioncompared to $3.38 billion for the corresponding period in 2016.
Details of the changes in retail electric revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | | First Quarter 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail electric – prior year | $ | 4,701 |
| | | | $ | 11,958 |
| | | | $ | 3,377 |
| | |
| Estimated change resulting from – | | | | | | | | | | | |
| Rates and pricing | 84 |
| | 1.8 |
| | 379 |
| | 3.2 |
| | 118 |
| | 3.5 |
|
| Sales growth (decline) | (18 | ) | | (0.4 | ) | | (14 | ) | | (0.1 | ) | |
| Sales decline | | | (11 | ) | | (0.3 | ) |
| Weather | 169 |
| | 3.6 |
| | 82 |
| | 0.7 |
| | (137 | ) | | (4.1 | ) |
| Fuel and other cost recovery | (128 | ) | | (2.7 | ) | | (473 | ) | | (4.0 | ) | | 47 |
| | 1.4 |
|
| Retail electric – current year | $ | 4,808 |
| | 2.3 | % | | $ | 11,932 |
| | (0.2 | )% | | $ | 3,394 |
| | 0.5 | % |
Revenues associated with changes in rates and pricing increased in the thirdfirst quarter and year-to-date 2016 when compared to the corresponding periods in 2015 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 year-to-date 2016 was the 2015 correction of a Georgia Power billing error to a small number of large commercial and industrial customers and the implementation of rates at Mississippi Power for certain Kemper IGCC in-service assets, effective September 2015.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power – Rate Plans" and " – Nuclear Construction," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the third quarter 20162017 when compared to the corresponding period in 2015. Industrial KWH sales decreased 3.3% in the third quarter 2016 primarily in the primary metals, paper, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2016 primarily due to decreased customer usage resulting from ana Rate RSE increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales decreased 0.4% inat Alabama Power effective January 1, 2017, the third quarter 2016 primarily due to decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting, partially offset by customer growth.
Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 2.1% for year-to-date 2016 primarily in the primary metals, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2016 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.
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 discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential sales increased 0.3%, weather-adjusted commercial sales decreased 0.5%, and industrial KWH sales decreased 2.0% as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues decreased $128 million and $473 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to a decrease in fuel prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
rate pricing effect of decreased customer usage and higher contributions from commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power, and an ECO Plan rate increase at Mississippi Power implemented in the third quarter 2016.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" and " – Georgia Power – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 2.2% in the first quarter 2017 primarily in the chemicals, stone, clay, and glass, and paper sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector. Weather-adjusted commercial KWH sales decreased 1.9% in thefirst quarter 2017 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 0.8% in the first quarter 2017primarily due to customer growth, partially offset by decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting.
Fuel and other cost recovery revenues increased $47 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in fuel prices. 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
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $93 | | 17.9 | | $20 | | 1.4 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $135 | | 34.1 |
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 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. SolarElectricity 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.charge or through a fixed price for electricity. As a result, Southern 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, 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.
In the thirdfirst quarter 2016,2017, wholesale electric revenues were $613$531 million compared to $520$396 million for the corresponding period in 2015.2016. This increase was primarily related to a $121$118 million increase in energy revenues partially offset byand a $28$17 million decreaseincrease in capacity revenues. For year-to-date 2016, wholesale electric revenues were $1.46 billion compared to $1.44 billion for the corresponding period in 2015. This increase was primarily related to a $112 millionThe increase in energy revenues partially offset by a $92 million decrease in capacity revenues. Theprimarily related to Southern Power increases in energy revenues were primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decreases in capacity revenues were primarily due to the elimination in consolidation of a Southern Power PPA that was remarketedarising from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 powernew solar and wind facilities, sales agreements at Gulf Power,from new natural gas PPAs, and the expiration of wholesale contracts at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power. Additionally, the year-to-date 2016 decrease in capacity revenues was due to unit retirements at Georgia Power.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings, and Gulf Power's request to rededicate its ownership interest in Scherer Unit 3 to the retail jurisdiction.
Other Electric Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 7.1 | | $35 | | 7.1 |
For year-to-date 2016, other electric revenues were $529 million compared to $494 million for the corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues, and solar application fee revenues at Georgia Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to PPAs related to new natural gas facilities and additional customer load requirements at Southern Power.
Natural Gas Revenues
Natural gas revenues represent sales from the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $518 million$1.5 billion of natural gas revenues are included in the consolidated statements of income for the thirdfirst quarter and year-to-date 2016.2017.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $133 | | N/M | | $247 | | N/M |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $103 | | N/M |
N/M - Not meaningful
In the thirdfirst quarter 2016,2017, other revenues were $144$141 million compared to $11$38 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $281 million compared to $34 million for the corresponding period in 2015. These increases were2016. The increase was primarily due to $91$70 million and $150 million for the third quarter and year-to-date 2016, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25$30 million of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, for the third quarter and year-to-date 2016, revenues from certain non-regulated sales of products and services by the traditional electric operating companies of $17 million and $63 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.
See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.
Fuel and Purchased Power Expenses
| | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (120 | ) | | (7.9) | | $ | (598 | ) | | (15.2) | | $ | 85 |
| | 9.3 |
| Purchased power | 34 |
| | 17.6 | | 74 |
| | 14.6 | | 14 |
| | 8.5 |
| Total fuel and purchased power expenses | $ | (86 | ) | | $ | (524 | ) | | | $ | 99 |
| |
In the thirdfirst quarter 2016,2017, total fuel and purchased power expenses were $1.6$1.2 billion compared to $1.7$1.1 billion for the corresponding period in 2015.2016. The decreaseincrease was primarily the result of a $209$121 million decreaseincrease in the average cost of fuel and purchased power primarily due to lower coal prices, partially offset by a $123 million increase in the volume of KWHs generated and purchased.
For year-to-date 2016, total fuel and purchased power expenses were $3.9 billion compared to $4.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $573 million decrease in the average cost of fuel and purchased power primarily due to lower coal andhigher natural gas prices, partially offset by a $49$22 million net increasedecrease 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the Southern Company system's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | | First Quarter 2017 | | First Quarter 2016 |
Total generation (in billions of KWHs) | 56 | | 53 | | 145 | | 146 | | 44 | | 44 |
Total purchased power (in billions of KWHs) | 5 | | 4 | | 13 | | 10 | | 4 | | 4 |
Sources of generation (percent) — | | | |
| Coal | 38 | | 40 | | 33 | | 37 | | 29 | | 27 |
| Nuclear | 15 | | 15 | | 16 | | 16 | | 17 | | 17 |
| Gas | 44 | | 43 | | 46 | | 44 | | 46 | | 47 |
| Hydro | 1 | | 1 | | 3 | | 2 | | 2 | | 7 |
| Other Renewables | 2 | | 1 | | 2 | | 1 | |
| Other | | | 6 | | 2 |
Cost of fuel, generated (in cents per net KWH) — | | | |
| Coal | 2.97 | | 3.86 | | 3.10 | | 3.65 | | 2.88 | | 3.24 |
| Nuclear | 0.81 | | 0.84 | | 0.82 | | 0.78 | | 0.79 | | 0.82 |
| Gas | 2.74 | | 2.71 | | 2.40 | | 2.72 | | 2.92 | | 2.16 |
Average cost of fuel, generated (in cents per net KWH) | 2.54 | | 2.90 | | 2.38 | | 2.78 | | 2.50 | | 2.23 |
Average cost of purchased power (in cents per net KWH)(*) | 5.57 | | 5.95 | | 5.31 | | 6.13 | | 6.11 | | 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. |
Fuel
In the thirdfirst quarter 2016,2017, fuel expense was $1.4 billion$996 million compared to $1.5 billion$911 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to a 23.1%35.2% increase in the average cost of natural gas per KWH generated and a 5.5% increase in the volume of KWHs generated by coal, partially offset by an 11.1% decrease in the average cost of coal per KWH generated partially offset byand an 8.7% increase8.4% decrease in the volume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $3.3 billion compared to $3.9 billion for the corresponding period in 2015. The decrease was primarily due to a 15.1% decrease in the average cost of coal per KWH generated, an 11.9% decrease in the volume of KWHs generated by coal, and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.1% increase in the volume of KWHs generated by natural gas.
Purchased Power
In the thirdfirst quarter 2016,2017, purchased power expense was $227$179 million compared to $193$165 million for the corresponding period in 2015.2016. The increase was primarily due to a 24.1%15.9% increase in the volume of KWHs purchased, partially offset by a 6.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.
For year-to-date 2016, purchased power expense was $581 million compared to $507 million for the corresponding period in 2015. The increase was primarily due tohigher natural gas prices, partially offset by a 29.4% increase3.6% decrease in the volume of KWHs purchased, partially offset by a 13.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.purchased.
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 Natural Gas
Cost of natural gas represents the cost of natural gas sold by the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $719 million of natural gas costs were included in the consolidated statements of income for the first quarter 2017.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cost of Natural GasOther Sales
Cost of natural gas represents |
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $69 | | N/M |
N/M - Not meaningful
In the first quarter 2017, cost of natural gas sold by the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $133other sales were $88 million of natural gas costs is included in the consolidated statements of incomecompared to $19 million for the third quartercorresponding period in 2016. The increase was primarily due to costs related to sales of products and year-to-dateservices by PowerSecure, which was acquired on May 9, 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Cost of Other Sales
In the third quarter and year-to-date 2016, cost of other sales were $84 million and $161 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, of $69 million and $111 million for the third quarter and year-to-date 2016, respectively. Additionally, for the third quarter and year-to-date 2016, costs of $11 million and $43 million, respectively, related to certain non-regulated sales of products and services by the traditional electric operating companies were reclassified as cost of other sales for consistency of presentation on a consolidated basis. In prior periods, these costs were included in other income (expense), net.
See "Other Revenues" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure International, Inc." herein for additional information.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $314 | | 28.6 | | $296 | | 8.9 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $222 | | 20.1 |
In the thirdfirst quarter 2016,2017, other operations and maintenance expenses were $1.4$1.3 billion compared to $1.1 billion for the corresponding period in 2015.2016. The increase was primarily relateddue to $251$253 million in operations and maintenance expenses at Southern Company Gas following the Merger, $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a $26 million charge in connection with an employee attrition plan at Georgia Power, a $19 million increase in transmissionsettlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), and distribution expenses primarily related to overhead line maintenance at Georgia Power, $18$21 million in operations and maintenance expenses at PowerSecure, and a $9 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 andwhich was acquired on May 9, 2016, partially offset by an $11a decrease of $38 million net decrease in employee compensation and benefits, including pension costs.
For year-to-date 2016, other operations and maintenance expenses were $3.6 billion compared to $3.3 billion for the corresponding period in 2015. The increase was primarily due to $251 million in operations and maintenance expenses at Southern Company Gas following the Merger, $28 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, a $28 million increase in transaction fees related to the Merger and the acquisition of PowerSecure, a $27 million increase in transmission and distribution expenses primarily related to overhead line maintenance and integrated transmission system billings at Georgia Power, a $26 million charge in connection with an employee attrition plan at Georgia Power, and a $22 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. The increase was partially offset by a $53 million decrease in scheduled outage and maintenance costs at generation facilities and a $48$19 million net decreaseincrease in employee compensation and benefits, including pension costs.gains from sales of integrated transmission system assets at Georgia Power.
See Note (F)(B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information related to pension costsregarding the 2017 Rate Case Settlement Agreement and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $175 | | 32.3 |
In the first quarter 2017, depreciation and amortization was $716 million compared to $541 million for the corresponding period in 2016. Following the Merger, $120 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for the first quarter 2017. Additionally, the increase reflects $60 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $20 million more of a reduction in depreciation in the first quarter 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information. Also, see Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $167 | | 31.6 | | $290 | | 19.1 |
In the third quarter 2016, depreciation and amortization was $695 million compared to $528 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $1.8 billion compared to $1.5 billion for the corresponding period in 2015. Following the Merger, $116 million in depreciation and amortization for Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, the increases were due to additional plant in service at the traditional electric operating companies and Southern Power.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $45 | | 17.0 | | $60 | | 7.9 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $74 | | 28.9 |
In the thirdfirst quarter 2016,2017, taxes other than income taxes were $309$330 million compared to $264$256 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $821 million compared2016. The increase primarily related to $761 million for the corresponding period in 2015. Following the Merger, $29$70 million in taxes other than income taxes associated with Southern Company Gas is included infollowing the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, property taxes at the traditional electric operating companies increased for the third quarter and year-to-date 2016 primarily due to an increase in the assessed value of property.Merger.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(62) | | (41.3) | | $40 | | 22.0 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $55 | | N/M |
N/M - Not meaningful
In the thirdfirst quarter 20162017 and 2015,2016, estimated probable losses on the Kemper IGCC of $88$108 million and $150 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $222 million and $182$53 million, respectively, were recorded at Southern Company. These losses reflect 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 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 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).
See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Earnings from Equity Method Investments
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $39 | | N/M |
N/M - Not meaningful
In the first quarter 2017, earnings from equity method investments were $39 million, primarily related to earnings from Southern Company Gas' equity method investment in SNG effective September 2016.
See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $156 | | 71.6 | | $301 | | 49.2 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $170 | | 69.1 |
In the thirdfirst quarter 2016,2017, interest expense, net of amounts capitalized was $374$416 million compared to $218$246 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized2016. The increase was $913 million compared to $612 million in the corresponding period in 2015. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the financing of the Merger.Merger and the funding of Southern Power's growth strategy and continuous construction program. In addition, following the Merger, $39$46 million in interest expense of Southern Company Gas is included in the consolidated financial statements of income for the thirdfirst quarter and year-to-date 2016. Also contributing to the year-to-date 2016 increase was the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits.2017.
See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net |
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $42 | | N/M | | $3 | | 7.3 |
N/M - Not meaningful
In the third quarter 2016, other income (expense), net was $21 million compared to $(21) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(38) million compared to $(41) million for the corresponding period in 2015. Following the Merger, $38 million in other income of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016, primarily related to $27 million of earnings from the equity method investment in Southern Natural Gas Company, L.L.C. (SNG) in September 2016. Additionally, in the third quarter 2016, revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the third quarter and year-to-date 2016, net amounts reclassified were $6 million and $20 million, respectively. The year-to-date 2016 increase was partially offset by fees associated with the Bridge Agreement for the Merger.
See "Other Revenues" and "Cost of Other Sales" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information. Also see
Other Income (Expense), Net |
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $23 | | 79.3 |
In the first quarter 2017, other income (expense), net was $(6) million compared to $(29) million for the corresponding period in 2016. The change was primarily due to parent company expenses incurred in 2016 associated with bridge financing for the Merger. The change also includes a currency loss of $17 million at Southern Power arising from a translation of euro-denominated fixed-rate notes into U.S. dollars, fully offset by a gain of $17 million on the related foreign currency hedge that was reclassified from accumulated OCI into earnings.
See Note 12(H) to the financial statements of Southern CompanyCondensed Financial Statements under "Southern Company – Merger Financing" in Item 8 of the Form 10-K"Foreign Currency Derivatives" herein for additional information.
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(52) | | (10.4) | | $(134) | | (12.5) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $98 | | 45.2 |
In the thirdfirst quarter 2016,2017, income taxes were $448$315 million compared to $500$217 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to increased federal income$150 million in taxes at Southern Company Gas following the Merger and a $12 million increase related to a decrease in tax benefits from solar ITCs and PTCs at Southern Power, partially offset by a reductionincreases in tax benefits of $30 million from wind PTCs at Southern Power, $21 million related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC at Mississippi Power, and an increase in pre-tax earnings.
For year-to-date 2016, income taxes were $942$9 million compared to $1.1 billion for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCsstate apportionment rate changes at Southern Power.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power, partially offset by an increase in pre-tax earnings and an increase related to state income tax benefits realized in 2015.
See Note (G) to the Condensed Financial Statements herein and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above 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 and as a result of closing the Merger, the distribution ofdistributing natural gas. These factors include the traditional electric operating companies' and Southern Company Gas'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 next several years. The completion of construction and subsequent operationresolution of cost recovery relating to the Kemper IGCC and the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 as well asare other ongoing construction projects. Other major factors includefactors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects. projects are also major factors.
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.
Future earnings for the electricity and 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 customers whichhigher multi-family home construction. 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 prices 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, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gas demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Volatility In addition, the volatility of natural gas prices has a significant impact on Southern Company Gas'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 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 affect the business operations, risks, and financial condition of Southern Company.
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company 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. In addition, the agreement committed Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations 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.long-term wholesale agreements for the traditional electric operating companies and Southern Power. 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. Further, higher 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS),revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all units within the Southern Company system that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016,planned reconsideration, the EPA issued proposed revisionsalso announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to the regional haze regulations. that effect.
The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Georgia Power's and Gulf Power's service territories as attainment for the 2012 annual fine particulate matter NAAQS. Following the EPA's decision, all areas within the traditional electric operating companies' service territory have now been designated as attainment for the 2012 fine particulate matter NAAQS.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama, Mississippi, and Texas and removing Florida and North Carolina from the program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Coal Combustion ResidualsGlobal Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of September 30, 2016.
Environmental Remediation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – EnvironmentalRemediation"Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information.
As a resultOn March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of closingdomestically produced energy resources. The executive order specifically directs the Merger, Southern Company's Consolidated Balance SheetEPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at September 30, 2016 includes the environmental remediation liabilities of Southern Company Gas. See Note (B) to the Condensed Financial Statements under "Environmental Remediation" herein for additional information. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.this time.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Retail Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory"Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding retail fuel cost recovery.recovery for the traditional electric operating companies.
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.
On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.
In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.
As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated RECs is specified in each respective PPA. The party that owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute toOf the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.
On October 11, 2016, the Florida PSC preliminarily approved Gulf Power's energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.
In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service byin 2017, one was placed in service in the secondfirst quarter 2017, andwhile the resulting energy purchasesremaining two are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.placed in service in June and July 2017. Mississippi Power may retire the RECsrenewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
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 its Rate RSE, Rate CNP, Compliance, rate energy cost recovery,Rate ECR, and rate natural disaster reserve.Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power 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.
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 tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing 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 (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
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 on April 14, 2016, Georgia Power's 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 (collectively, Utilities) 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 utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory"Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision 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 will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative 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.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of cost recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's 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 of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gulf Power
Through 2015, long-term non-affiliateSee MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity sales fromcost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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) provided, which was recorded in the majorityfirst quarter 2017. The remaining issues related to the inclusion of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of Gulf Power's wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownershipinvestment in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 andhave been resolved as a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverabilityresult of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 20162017 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors includeSettlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Gulf Power– Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.
Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas 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.flows.
Regulatory Infrastructure ProgramsBase Rate Cases
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 update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern CompanyOn March 10, 2017, Nicor Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years,filed a general base rate case with the longest setIllinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and an ROE of 10.7%. The Illinois Commission is expected to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.
Southern Company Gas currently has proposed infrastructure improvement programs pending approval byrule on the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively.requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of these mattersthis matter cannot be determined at this time.
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
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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 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 thatdesigned to update or expand itsthe natural gas distribution systems of the natural gas distribution utilities to improve reliability and ensure the safety of its utility infrastructuremeet operational flexibility and recovers in rates itsgrowth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs.programs through their regulated rates.
The two largest construction projects currently underway in the Southern Company system are 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 582-MW Kemper IGCC. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power – Construction Projects" herein. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters –Southern Company Gas –
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Regulatory Infrastructure Programs"Programs" herein for additional information regarding infrastructure improvement programs at Southern Company Gas'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.
Integrated Coal Gasification Combined Cycle
Mississippi Power'sPower continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The current cost estimate for the Kemper IGCC in total is approximately $6.82$7.16 billion, which includes approximately $5.52$5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE grants Mississippi Power received for the Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts forto customers. 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 Initial DOE Grants and excluding the Cost Cap Exceptions. InSouthern Company recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2013, in the aggregate, Southern Company has incurred charges of $2.63$2.87 billion ($1.631.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. Mississippi Power'sMarch 31, 2017. The current cost estimate includes costs through DecemberMay 31, 2016.
The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A,"2017, as well as identified costs to complete the integration of all systems necessary for both combustion turbinesbe incurred beyond May 31, 2017, expected to simultaneously generate electricity with syngas.
In subsequent periods, any further changes in the estimated costs of the Kemper IGCCbe subject to the $2.88 billion cost cap,cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.
In December 2015, the Mississippi PSC issued an order, based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. Upon placing the remainder of the plant in service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.
Mississippi Power is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE GrantsGrants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and excludingwholesale rates for the Cost Cap Exceptions,assets in service, and the remainder will be reflectedthe subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale Municipal and Rural Associations rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in Southern Company's statementsaccordance with the requirements of incomethe 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and these changes could be material.
The ultimate outcome of these matters cannot be determined at this time.future
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operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
In connection with the 2017 Rate Case, Mississippi Power expects to request authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Southern Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of these matters cannot now be determined but could result in further charges that could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" and "Other Matters" herein.
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. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, theMississippi. The plaintiffs have filed a request to remand the case back to state court.court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, 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
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and schedule of the Kemper IGCC 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 IGCC; 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 IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.
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 relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court is expected to address in the second quarter 2017.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in 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, and the ultimate outcome of these matters cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
Vogtle 3 and 4 Agreement and Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.
On October 20,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 litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based
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on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.
Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment
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Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC Staff entered intoand the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
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 by including the related CWIP accounts in rate base during the construction period.
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On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence and cost recovery matters related to Plant Vogtle Units 3 and 4:matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth Vogtle Construction MonitoringVCM report will be disallowed from rate base on the basis of imprudence; (ii) the definitive settlement agreement entered into on December 31, 2015 by Westinghouse and the Vogtle Owners (ContractorContractor Settlement Agreement)Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both
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the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation,when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject toGeorgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval byof $222 million of construction capital costs incurred during that period, with the Georgia PSC which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduceFebruary 27, 2017. Georgia Power's revenuesCWIP balance for the years 2016Plant Vogtle Units 3 and 4 was approximately $4.1 billion as of March 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs through 2020 by a total of approximately $325 million ($115 million reduction in net income).
See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Georgia Power– Nuclear Construction" for additional information.March 31, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of March 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
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. Processes are in place
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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 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.
As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the Contractor's bankruptcy.
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Matters" of Southern Company in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expectedand Note (G) to result in approximately $1.7 billion of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016. See Note (B) tothe Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) tothe Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. 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 air quality and water standards, 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 in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofSouthernCompanyinItem8ofthe Form 10-K,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 (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain of Mississippi Power's former 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 of Mississippi Power's former officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions
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Statements hereinunder the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.
On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for a discussionthe Northern District of various other contingencies, regulatory matters,Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and other matters being litigated which may affect future earnings potential.certain of Mississippi Power's former officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC 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. Southern Company believes that this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believebelieves the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.
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 of Southern Company in Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2016,2017, 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 Initial 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 Initial 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 subject to the construction cost cap of $108 million ($67 million after tax) in the first quarter 2017, $127 million ($78 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, $53
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million ($33 million after tax) in the first quarter 2016, $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 $2.63$2.87 billion ($1.631.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.March 31, 2017.
Mississippi Power's revised cost estimate reflects an expected in-service date of DecemberMay 31, 20162017 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
In addition duringto the start-up and commissioning process,current construction cost estimate, Mississippi Power is also identifying
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. TheApproximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimates,estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial 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 extension of the in-service date beyond December 31, 2016the end of May 2017 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 tobeyond the Kemper IGCC beyond December 31, 2016end of May 2017 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 $15$16 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 $3 million per month.
Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further in Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Prudence," " – Lignite Mine and CO2 Pipeline Facilities," " – Termination of Proposed Sale of Undivided Interest," and " – Income Tax Matters" herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Southern Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
GoodwillRecently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and Other Intangible Assetsindustry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the 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.
While Southern Company accounts for acquisitions using the acquisition methodexpects most of accounting, which requires the assets acquired and liabilities assumedits revenue to be recordedincluded in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority 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. For such arrangements, Southern Company expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Southern Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of acquisition at their respective estimated fair values.initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill will be 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 $6.2 billion at September 30, 2016.
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 mayhas not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, other intangible assets, net of amortization totaled approximately $0.9 billion at September 30, 2016.
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 (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" herein for additional information regarding Southern Company's goodwill and other intangible assets as of September 30, 2016 and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to Southern Company's recent acquisitions.elected its transition method.
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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 occurs 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 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 factors required under the guidance. 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 "Quantitative and Qualitative Disclosures About Market Risk" in Item 3 herein for more information.
Recently Issued Accounting Standards
On February 25, 2016,January 26, 2017, the FASB issued ASU No. 2016-02,2017-04, Leases(Topic 842)Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2016-02)2017-04). ASU 2016-022017-04 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 annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
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 lesseesthat 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 recognize onbe separately presented in the balance sheet a lease liability and a right-of-use assetincome statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all leases.cost components remain eligible for capitalization under FERC regulations. ASU 2016-02 also changes2017-07 will be applied retrospectively for the recognition, measurement, and presentation of expense associated with leasesthe service cost component and provides clarification regarding the identification of certainother components of contracts that would representnet periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases.prospective basis. ASU 2016-022017-07 is effective for fiscal yearsannual periods beginning after December 15, 2018, with early adoption permitted.2017, including interim periods within those annual periods. Southern Company is currently evaluating the new standardstandard. The presentation changes required for net periodic pension and has not yet determined its ultimate impact; however,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. The adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.
On March 30, 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. Most significantly, 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. Southern Company currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock
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compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company intends to adopt the ASU in the fourth quarter 2016. The adoption2017-07 is not expected to have a material impact on the results of operations,Southern Company's financial position, or cash flows of Southern Company.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 2016. Through September 30, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.March 31, 2017. Southern 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $4.3 billion$897 million for the first ninethree months of 2016, a decrease2017, an increase of $0.8 billion$19 million from the corresponding period in 2015.2016. The decreaseincrease in net cash provided from operating activities was primarily due to an increase$758 million of net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, largely offset by the timing of vendor payments and a decrease in unutilized ITCs and PTCs.fuel cost recovery. Net cash used for investing activities totaled $16.6$2.8 billion for the first ninethree months of 20162017 primarily due to the closing of the Merger, the construction of electric generation, transmission, and distribution facilities, and installation of equipment to comply with environmental standards, and Southern Power's acquisitionsacquisition and construction of renewable facilities. Net cash provided from financing activities totaled $13.6$1.0 billion for the first ninethree months of 20162017 primarily due to issuances of long-term debt, and common stock associated with financing and completing the Merger and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include an increase of $14.4$1.4 billion in total property, plant, and equipment primarily related to Southern Power's wind facility acquisition and the inclusiontraditional electric operating companies' installation of Southern Company Gas as a result of the Merger, constructionequipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities; a decrease of $0.9 billion in cash and cash equivalents primarily related to acquisition payments at Southern Power; an increase of $6.2$0.6 billion in goodwill notes payable primarily
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related to the acquisitions of Southern Company Gas and PowerSecure; an increase in commercial paper borrowings; and a decrease of $1.5$0.5 billion in equity investments in unconsolidated subsidiariesaccounts payable primarily related to Southern Company Gas' investment in SNG; increases of $1.5 billion in other regulatory assets, deferred and $0.8 billion in AROs primarily related to changes in ash pond closure strategy principally for Georgia Power; increases of $16.9 billion in long-term debt and $4.0 billion in total common stockholder's equity primarily associated with financing and completing the Merger and Southern Company Gas' investment in SNG; and increases of $1.9 billion in accumulated deferred income taxes and $1.6 billion in other cost of removal obligations primarily relateddue to the inclusiontiming of Southern Company Gas as a result of the Merger. See Notes (A) and (I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company," respectively, for additional information.vendor payments.
At the end of the thirdfirst quarter 2016,2017, the market price of Southern Company's common stock was $51.30$49.78 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.05$25.23 per share, representing a market-to-book ratio of 205%197%, compared to $46.79, $22.59,$49.19, $25.00, and 207%197%, respectively, at the end of 2015.2016. Southern Company's common stock dividend for the thirdfirst quarter 20162017 was $0.560$0.56 per share compared to $0.5425 per share in the thirdfirst quarter 2015.2016.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016 and Southern Company Gas repaid at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016. An additional $1.8Approximately $3.3 billion will be required through September 30, 2017March 31, 2018 to fund maturities of long-term debt. During the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements, which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total $10.2 billion for 2016, $8.9 billion for 2017, $8.2 billion for 2018, $7.6 billion for 2019, $7.3 billion for 2020, and $6.6 billion for 2021. These amounts include expenditures of approximately $0.7 billion for 2016 and $0.1 billion for 2017 related to the construction and start-up of the Kemper IGCC; $0.6 billion for 2016, $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction of Plant Vogtle Units 3 and 4; and $4.4 billion for 2016 and $1.5 billion per year for 2017 through 2021 for Southern Power's acquisitions and/or construction of new generating facilities. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
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 statutes 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. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As a result of closing the Merger, the funding requirements of the Southern Company system include the contractual obligations of Southern Company Gas. The following table details the amounts related to Southern Company Gas as of September 30, 2016:
|
| | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2017- 2018 | | 2019- 2020 | | After 2020 | | Total |
| | (in millions) |
Long-term debt(a) — | | | | | | | | | |
| Principal | $ | 120 |
| | $ | 177 |
| | $ | 350 |
| | $ | 4,185 |
| | $ | 4,832 |
|
| Interest | 48 |
| | 412 |
| | 382 |
| | 2,641 |
| | 3,483 |
|
Pipeline charges, storage capacity, and gas supply(b) | 308 |
| | 1,350 |
| | 806 |
| | 2,913 |
| | 5,377 |
|
Operating leases(c) | 6 |
| | 44 |
| | 31 |
| | 52 |
| | 133 |
|
Asset management agreements(d) | 2 |
| | 15 |
| | 2 |
| | — |
| | 19 |
|
Standby letters of credit, performance/surety bonds(e) | 33 |
| | 51 |
| | — |
| | — |
| | 84 |
|
Financial derivative obligations(f) | 195 |
| | 211 |
| | 21 |
| | 2 |
| | 429 |
|
Pension and other postretirement benefit plans(g) | 5 |
| | 44 |
| | — |
| | — |
| | 49 |
|
Purchase commitments — | | | | | | | | | |
Capital(h) | 401 |
| | 3,540 |
| | 3,058 |
| | 1,221 |
| | 8,220 |
|
Other(i) | 11 |
| | 53 |
| | — |
| | — |
| | 64 |
|
| Total | $ | 1,129 |
| | $ | 5,897 |
| | $ | 4,650 |
| | $ | 11,014 |
| | $ | 22,690 |
|
| |
(a) | Amounts are reflected based on final maturity dates. Variable rate interest obligations are estimated based on rates as of September 30, 2016. |
| |
(b) | Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with wholesale gas services. |
| |
(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. |
| |
(d) | Represents fixed-fee minimum payments for asset management agreements at wholesale gas services. |
| |
(e) | Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers of SouthStar Energy Services, LLC (SouthStar) in support of payment obligations. |
| |
(f) | Includes derivative liabilities related to energy-related derivatives. |
| |
(g) | Estimated benefit payments for Southern Company Gas' retirement benefit plans are provided through 2018. No mandatory contributions to the plans are anticipated during this period. |
| |
(h) | Estimated capital expenditures are provided through 2021. |
| |
(i) | Primarily consists of contractual environmental remediation liabilities that are primarily recoverable through base rates or rate rider mechanisms. |
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2016,2017, 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 Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS –
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
In addition, Georgia Power may make borrowings throughhas entered into a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power andwith the DOE, under which the proceeds of whichborrowings 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. Eligible Project Costs incurred through September 30, 2016March 31, 2017 would allow for borrowings of up to $2.6$2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5$2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. OnIn April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, seeSee Note 3(B) to the financial statements of Southern CompanyCondensed Financial Statements under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-Kherein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
As of September 30, 2016,March 31, 2017, Southern Company's current liabilities exceeded current assets by $0.9$3.9 billion, primarily due to long-term debt that is due within one year of $2.3$3.3 billion, including approximately $0.8$0.4 billion at the parent company, $0.2$0.4 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2$0.1 billion at Gulf Power, $0.3$1.3 billion at Mississippi Power, $0.1and $0.6 billion at Southern Power, and $0.1 billion at Southern Company Gas.Power. 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. In addition, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At September 30, 2016,March 31, 2017, Southern Company and its subsidiaries had approximately $2.7$1.1 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016March 31, 2017 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 | 2017 | 2018 | 2020 | | 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 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
| 85 |
| 195 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 25 |
| | 70 |
|
| Mississippi Power | 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
| 173 |
| — |
| — |
| | 173 |
| | 141 |
| | — |
| | 13 |
| | 13 |
| | 160 |
|
Southern Power Company(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| 600 |
| | 600 |
| | 524 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c)(b) | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,949 |
| | — |
| | — |
| | — |
| | 75 |
|
| Other | — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
|
| Southern Company Consolidated | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
| $ | 423 |
| $ | 3,620 |
| $ | 4,400 |
| | $ | 8,443 |
| | $ | 8,266 |
| | $ | 65 |
| | $ | 13 |
| | $ | 58 |
| | $ | 375 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3$1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 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 of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
On May 24, 2016, the $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Gulf 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 March 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, and Southern Company Gas, are currentlyand 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 electric 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 September 30, 2016March 31, 2017 was approximately $1.9 billion. In addition, at September 30, 2016,March 31, 2017, the traditional electric operating companies had approximately $358$386 million of fixed rate pollution control revenue bonds outstanding that were required to be reofferedremarketed within the next 12 months.
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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas may also borrow through various other arrangements with banks. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) | | Short-term Debt at March 31, 2017 | | 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) |
| Commercial paper | | $ | 717 |
| | 0.7 | % | | $ | 756 |
| | 0.7 | % | | $ | 1,499 |
| | $ | 2,682 |
| | 1.2 | % | | $ | 2,355 |
| | 1.1 | % | | $ | 2,885 |
|
| Short-term bank debt | | 125 |
| | 1.5 | % | | 125 |
| | 1.4 | % | | 127 |
| | 136 |
| | 2.2 | % | | 125 |
| | 1.8 | % | | 349 |
|
| Total | | $ | 842 |
| | 0.8 | % | | $ | 881 |
| | 0.8 | % | | | | $ | 2,818 |
| | 1.3 | % | | $ | 2,480 |
| | 1.1 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.March 31, 2017. |
In addition, toin connection with the short-term borrowings inconstruction of the table above, the Project Credit Facilities had total amounts outstanding asRoserock solar facility, RE Roserock LLC, an indirect subsidiary of September 30, 2016 of $828 million atSouthern Power, previously entered into a weighted average interest rate of 2.05%.credit agreement that was fully repaid on January 31, 2017. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of a solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016,March 31, 2017, this credit agreement had a maximum amount outstanding of $217$209 million and an average amount outstanding of $137$70 million at a weighted average interest rate of 2.21%2.1%.
Southern 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.
Credit Rating Risk
At September 30, 2016,March 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, foreign currency risk management, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2016March 31, 2017 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 31 |
| $ | 39 |
|
| At BBB- and/or Baa3 | $ | 665 |
| $ | 659 |
|
| Below BBB- and/or Baa3 | $ | 2,570 |
| |
At BB+ and/or Ba1(*) | | $ | 2,649 |
|
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| |
| (*) | 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 impact the cost at which they do so.
On May 12, 2016, FitchMarch 1, 2017, Moody's downgraded the senior unsecured long-term debt rating of Southern Company to A- from A and revised the ratings outlook from negative to stable. Fitch also downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+Ba1 from A- and revised the ratings outlook from negative to stable.Baa3.
On May 13, 2016,March 20, 2017, Moody's downgraded the senior unsecured long-term debtrevised its rating of Southern Company to Baa2outlook for Georgia Power from Baa1 and revised the ratings outlook from negative to stable.
On July 11, 2016, S&P raised Southern Company Gas' and Nicor Gas' corporate and senior unsecured long-term debt ratings from BBB+ to A- and revised their ratings outlooks from positivestable to negative.
Financing Activities
On May 11, 2016, Southern Company issued 18.3 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $889 million. Of the 18.3 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and for other general corporate purposes.
On August 19, 2016, Southern Company issued 32.5 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $1.6 billion. The proceeds were used to fund a portion of the purchase price for the SNG investment and related transaction costs and for other general corporate purposes.
In addition, during the first nine months of 2016, Southern Company issued approximately 17.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $782 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2016:
|
| | | | | | | | | | | | | | | | | | | |
| Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue Bond Maturities, Redemptions, and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) |
| | (in millions) |
Southern Company(b) | $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
|
| Georgia Power | 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | 2 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 652 |
|
| Southern Power | 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
|
Southern Company Gas(c) | 900 |
| | 300 |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | 60 |
|
Elimination(d) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) |
| Southern Company Consolidated | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
|
| |
(a) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b) | Represents the Southern Company parent entity. |
| |
(c) | Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas. |
| |
(d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In February 2016,On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company entered into $700 million notional amountand 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 placed the ratings of forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.Southern Company, Georgia Power, and Mississippi Power on rating watch negative.
In May 2016,Financing Activities
During the first three months of 2017, Southern Company issued the following seriesapproximately 4.2 million shares of senior notes for an aggregate principal amountcommon stock primarily through employee equity compensation plans and received proceeds of $8.5 billion:
$0.5 billion of 1.55% Senior Notes due July 1, 2018;
$1.0 billion of 1.85% Senior Notes due July 1, 2019;
$1.5 billion of 2.35% Senior Notes due July 1, 2021;
$1.25 billion of 2.95% Senior Notes due July 1, 2023;
$1.75 billion of 3.25% Senior Notes due July 1, 2026;
$0.5 billion of 4.25% Senior Notes due July 1, 2036; and
$2.0 billion of 4.40% Senior Notes due July 1, 2046.approximately $186 million.
The net proceeds were used to fund a portion offollowing table outlines the considerationlong-term debt financing activities for Southern Company and its subsidiaries for the Merger and related transaction costs and for other general corporate purposes.first three months of 2017:
|
| | | | | | | | | | | | | | | |
Company(a) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(b) |
| | (in millions) |
Southern Company(c) | $ | — |
| | $ | — |
| | $ | — |
| | $ | 400 |
|
| Alabama Power | 550 |
| | 200 |
| | — |
| | — |
|
| Georgia Power | 850 |
| | — |
| | — |
| | 2 |
|
| Gulf Power | — |
| | — |
| | 6 |
| | — |
|
| Southern Power | — |
| | — |
| | 3 |
| | 2 |
|
| Other | — |
| | — |
| | — |
| | 4 |
|
| Southern Company Consolidated | $ | 1,400 |
| | $ | 200 |
| | $ | 9 |
| | $ | 408 |
|
| |
| (a) | Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017. |
| |
| (b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (c) | Represents the Southern Company parent entity. |
In September 2016,March 2017, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repayrepaid at maturity $500a $400 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.18-month floating rate bank loan.
Except as described herein, Southern Company's 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 their continuous construction programs and, for Southern Power, its growth strategy.
On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.programs.
In May 2016,March 2017, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.
Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings in June 2016 under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of a solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320a $100 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amountshort-term floating rate bank loan bearing interest based on one-month LIBOR due Septemberfrom April 2017 to October 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar, to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) to the Condensed Financial Statements under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" herein for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.
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.
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Other thanDuring the changes resulting from the Merger discussed below, during the ninethree months ended September 30, 2016,March 31, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, orand Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, and Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
As a result of closing the Merger, the Southern Company system's exposure to market risks includes Southern Company Gas. Southern Company Gas 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 Southern Company Gas that sell natural gas directly to their end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas 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, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower 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 energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. If there is a significant change in the underlying market prices or pricing assumptions Southern Company uses to price the derivative assets or liabilities, such changes may have a significant impact on Southern Company's financial position, results of operations, and cash flows.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern PowerCompany Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 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.
| |
| (b) | Changes in internal controls over financial reporting. |
Other than the changes resulting from the Merger discussed below, thereThere 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'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 thirdfirst quarter 20162017 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'sCompany Gas' internal control over financial reporting.
Southern Company completed the Merger on July 1, 2016, with Southern Company Gas surviving the Merger as a wholly-owned, direct subsidiary of Southern Company. Southern Company is currently in the process of integrating Southern Company Gas' operations and conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley
Act of 2002. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.
ALABAMA POWER COMPANY
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Retail revenues | $ | 1,629 |
| | $ | 1,558 |
| | $ | 4,139 |
| | $ | 4,151 |
| $ | 1,227 |
| | $ | 1,193 |
|
| Wholesale revenues, non-affiliates | 82 |
| | 65 |
| | 211 |
| | 188 |
| 66 |
| | 63 |
|
| Wholesale revenues, affiliates | 18 |
| | 20 |
| | 49 |
| | 55 |
| 33 |
| | 22 |
|
| Other revenues | 56 |
| | 52 |
| | 162 |
| | 157 |
| 56 |
| | 53 |
|
| Total operating revenues | 1,785 |
| | 1,695 |
| | 4,561 |
| | 4,551 |
| 1,382 |
| | 1,331 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 410 |
| | 408 |
| | 973 |
| | 1,061 |
| 298 |
| | 268 |
|
| Purchased power, non-affiliates | 63 |
| | 56 |
| | 139 |
| | 142 |
| 34 |
| | 36 |
|
| Purchased power, affiliates | 41 |
| | 51 |
| | 129 |
| | 153 |
| 28 |
| | 33 |
|
| Other operations and maintenance | 348 |
| | 371 |
| | 1,097 |
| | 1,140 |
| 369 |
| | 392 |
|
| Depreciation and amortization | 177 |
| | 163 |
| | 524 |
| | 481 |
| 181 |
| | 172 |
|
| Taxes other than income taxes | 96 |
| | 91 |
| | 286 |
| | 275 |
| 96 |
| | 97 |
|
| Total operating expenses | 1,135 |
| | 1,140 |
| | 3,148 |
| | 3,252 |
| 1,006 |
| | 998 |
|
| Operating Income | 650 |
| | 555 |
| | 1,413 |
| | 1,299 |
| 376 |
| | 333 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Allowance for equity funds used during construction | 7 |
| | 14 |
| | 23 |
| | 43 |
| 8 |
| | 10 |
|
| Interest expense, net of amounts capitalized | (77 | ) | | (71 | ) | | (224 | ) | | (205 | ) | (75 | ) | | (73 | ) |
| Other income (expense), net | (5 | ) | | (7 | ) | | (16 | ) | | (24 | ) | (5 | ) | | (8 | ) |
| Total other income and (expense) | (75 | ) | | (64 | ) | | (217 | ) | | (186 | ) | (72 | ) | | (71 | ) |
| Earnings Before Income Taxes | 575 |
| | 491 |
| | 1,196 |
| | 1,113 |
| 304 |
| | 262 |
|
| Income taxes | 221 |
| | 192 |
| | 466 |
| | 427 |
| 126 |
| | 102 |
|
| Net Income | 354 |
| | 299 |
| | 730 |
| | 686 |
| 178 |
| | 160 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 21 |
| 4 |
| | 4 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 350 |
| | $ | 295 |
| | $ | 717 |
| | $ | 665 |
| $ | 174 |
| | $ | 156 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Net Income | $ | 354 |
| | $ | 299 |
| | $ | 730 |
| | $ | 686 |
| $ | 178 |
| | $ | 160 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
Changes in fair value, net of tax of $-, $(4), $(1), and $(4),
respectively | — |
| | (6 | ) | | (2 | ) | | (6 | ) | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $1, respectively | 1 |
| | — |
| | 3 |
| | 1 |
| |
| Changes in fair value, net of tax of $- and $(1), respectively | | — |
| | (2 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $1 and $1, respectively | | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | (6 | ) | | 1 |
| | (5 | ) | 1 |
| | (1 | ) |
| Comprehensive Income | $ | 355 |
| | $ | 293 |
| | $ | 731 |
| | $ | 681 |
| $ | 179 |
| | $ | 159 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 730 |
| | $ | 686 |
| $ | 178 |
| | $ | 160 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 634 |
| | 585 |
| 219 |
| | 211 |
|
| Deferred income taxes | 267 |
| | 85 |
| 59 |
| | 68 |
|
| Allowance for equity funds used during construction | (23 | ) | | (43 | ) | |
| Other, net | (23 | ) | | 23 |
| (3 | ) | | (14 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (4 | ) | | (160 | ) | 30 |
| | 191 |
|
| -Fossil fuel stock | 18 |
| | 69 |
| 10 |
| | (27 | ) |
| -Other current assets | (46 | ) | | (10 | ) | (87 | ) | | (87 | ) |
| -Accounts payable | (113 | ) | | (106 | ) | (214 | ) | | (143 | ) |
| -Accrued taxes | 203 |
| | 371 |
| 77 |
| | 66 |
|
| -Accrued compensation | | (96 | ) | | (75 | ) |
| -Retail fuel cost over recovery | (104 | ) | | 81 |
| (36 | ) | | (1 | ) |
| -Other current liabilities | (4 | ) | | (2 | ) | (9 | ) | | (8 | ) |
| Net cash provided from operating activities | 1,535 |
| | 1,579 |
| 128 |
| | 341 |
|
| Investing Activities: | | | | | | |
| Property additions | (947 | ) | | (938 | ) | (306 | ) | | (313 | ) |
| Nuclear decommissioning trust fund purchases | (275 | ) | | (349 | ) | (63 | ) | | (105 | ) |
| Nuclear decommissioning trust fund sales | 275 |
| | 349 |
| 63 |
| | 105 |
|
| Cost of removal, net of salvage | (70 | ) | | (41 | ) | (26 | ) | | (31 | ) |
| Change in construction payables | (37 | ) | | (48 | ) | 5 |
| | (15 | ) |
| Other investing activities | (28 | ) | | (22 | ) | (2 | ) | | (9 | ) |
| Net cash used for investing activities | (1,082 | ) | | (1,049 | ) | (329 | ) | | (368 | ) |
| Financing Activities: | | | | | | |
| Proceeds — | | | | | | |
| Senior notes | 400 |
| | 975 |
| 550 |
| | 400 |
|
| Capital contributions from parent company | 253 |
| | 13 |
| 314 |
| | 236 |
|
| Pollution control revenue bonds | — |
| | 80 |
| |
| Other long-term debt | 45 |
| | — |
| — |
| | 45 |
|
| Redemptions and repurchases — |
|
| |
| |
| Preferred and preference stock | — |
| | (412 | ) | |
| Pollution control revenue bonds | — |
| | (134 | ) | |
| Senior notes | (200 | ) | | (250 | ) | |
| Redemptions and repurchases — Senior notes | | (200 | ) | | (200 | ) |
| Payment of common stock dividends | (574 | ) | | (428 | ) | (179 | ) | | (191 | ) |
| Other financing activities | (15 | ) | | (38 | ) | (8 | ) | | (13 | ) |
| Net cash used for financing activities | (91 | ) | | (194 | ) | |
| Net cash provided from financing activities | | 477 |
| | 277 |
|
| Net Change in Cash and Cash Equivalents | 362 |
| | 336 |
| 276 |
| | 250 |
|
| Cash and Cash Equivalents at Beginning of Period | 194 |
| | 273 |
| 420 |
| | 194 |
|
| Cash and Cash Equivalents at End of Period | $ | 556 |
| | $ | 609 |
| $ | 696 |
| | $ | 444 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $8 and $15 capitalized for 2016 and 2015, respectively) | $ | 215 |
| | $ | 192 |
| |
| Interest (net of $3 and $4 capitalized for 2017 and 2016, respectively) | | $ | 84 |
| | $ | 76 |
|
| Income taxes, net | (70 | ) | | 47 |
| — |
| | (162 | ) |
| Noncash transactions — Accrued property additions at end of period | 84 |
| | 88 |
| 90 |
| | 106 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 696 |
| | $ | 420 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 326 |
| | 348 |
|
| Unbilled revenues | | 127 |
| | 146 |
|
| Other accounts and notes receivable | | 31 |
| | 27 |
|
| Affiliated | | 35 |
| | 40 |
|
| Accumulated provision for uncollectible accounts | | (10 | ) | | (10 | ) |
| Fossil fuel stock | | 195 |
| | 205 |
|
| Materials and supplies | | 444 |
| | 435 |
|
| Prepaid expenses | | 106 |
| | 34 |
|
| Other regulatory assets, current | | 141 |
| | 149 |
|
| Other current assets | | 8 |
| | 11 |
|
| Total current assets | | 2,099 |
| | 1,805 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 26,134 |
| | 26,031 |
|
| Less: Accumulated provision for depreciation | | 9,241 |
| | 9,112 |
|
| Plant in service, net of depreciation | | 16,893 |
| | 16,919 |
|
| Nuclear fuel, at amortized cost | | 332 |
| | 336 |
|
| Construction work in progress | | 642 |
| | 491 |
|
| Total property, plant, and equipment | | 17,867 |
| | 17,746 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 65 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 825 |
| | 792 |
|
| Miscellaneous property and investments | | 113 |
| | 112 |
|
| Total other property and investments | | 1,003 |
| | 970 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 526 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | — |
| | 150 |
|
| Other regulatory assets, deferred | | 1,218 |
| | 1,157 |
|
| Other deferred charges and assets | | 156 |
| | 163 |
|
| Total deferred charges and other assets | | 1,900 |
| | 1,995 |
|
| Total Assets | | $ | 22,869 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 361 |
| | $ | 561 |
|
| Accounts payable — | | | | |
| Affiliated | | 224 |
| | 297 |
|
| Other | | 232 |
| | 433 |
|
| Customer deposits | | 90 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 95 |
| | 45 |
|
| Other accrued taxes | | 65 |
| | 42 |
|
| Accrued interest | | 65 |
| | 78 |
|
| Accrued compensation | | 95 |
| | 193 |
|
| Other regulatory liabilities, current | | 45 |
| | 85 |
|
| Other current liabilities | | 71 |
| | 76 |
|
| Total current liabilities | | 1,343 |
| | 1,898 |
|
| Long-term Debt | | 7,081 |
| | 6,535 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,714 |
| | 4,654 |
|
| Deferred credits related to income taxes | | 65 |
| | 65 |
|
| Accumulated deferred investment tax credits | | 108 |
| | 110 |
|
| Employee benefit obligations | | 288 |
| | 300 |
|
| Asset retirement obligations | | 1,523 |
| | 1,503 |
|
| Other cost of removal obligations | | 667 |
| | 684 |
|
| Other regulatory liabilities, deferred | | 88 |
| | 100 |
|
| Other deferred credits and liabilities | | 70 |
| | 63 |
|
| Total deferred credits and other liabilities | | 7,523 |
| | 7,479 |
|
| Total Liabilities | | 15,947 |
| | 15,912 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
|
| 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 | | 2,936 |
| | 2,613 |
|
| Retained earnings | | 2,513 |
| | 2,518 |
|
| Accumulated other comprehensive loss | | (30 | ) | | (30 | ) |
| Total common stockholder's equity | | 6,641 |
| | 6,323 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,869 |
| | $ | 22,516 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 556 |
| | $ | 194 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 440 |
| | 332 |
|
| Unbilled revenues | | 155 |
| | 119 |
|
| Under recovered regulatory clause revenues | | 52 |
| | 43 |
|
| Income taxes receivable, current | | — |
| | 142 |
|
| Other accounts and notes receivable | | 43 |
| | 20 |
|
| Affiliated | | 30 |
| | 50 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) |
| Fossil fuel stock | | 220 |
| | 239 |
|
| Materials and supplies | | 420 |
| | 398 |
|
| Vacation pay | | 66 |
| | 66 |
|
| Prepaid expenses | | 56 |
| | 83 |
|
| Other regulatory assets, current | | 73 |
| | 115 |
|
| Other current assets | | 9 |
| | 10 |
|
| Total current assets | | 2,111 |
| | 1,801 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 25,800 |
| | 24,750 |
|
| Less accumulated provision for depreciation | | 9,018 |
| | 8,736 |
|
| Plant in service, net of depreciation | | 16,782 |
| | 16,014 |
|
| Nuclear fuel, at amortized cost | | 345 |
| | 363 |
|
| Construction work in progress | | 473 |
| | 801 |
|
| Total property, plant, and equipment | | 17,600 |
| | 17,178 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 67 |
| | 71 |
|
| Nuclear decommissioning trusts, at fair value | | 781 |
| | 737 |
|
| Miscellaneous property and investments | | 105 |
| | 96 |
|
| Total other property and investments | | 953 |
| | 904 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 518 |
| | 522 |
|
| Deferred under recovered regulatory clause revenues | | 87 |
| | 99 |
|
| Other regulatory assets, deferred | | 1,070 |
| | 1,114 |
|
| Other deferred charges and assets | | 118 |
| | 103 |
|
| Total deferred charges and other assets | | 1,793 |
| | 1,838 |
|
| Total Assets | | $ | 22,457 |
| | $ | 21,721 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 236 |
| | $ | 200 |
|
| Accounts payable — | | | | |
| Affiliated | | 309 |
| | 278 |
|
| Other | | 233 |
| | 410 |
|
| Customer deposits | | 88 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 73 |
| | — |
|
| Other accrued taxes | | 125 |
| | 38 |
|
| Accrued interest | | 69 |
| | 73 |
|
| Accrued vacation pay | | 55 |
| | 55 |
|
| Accrued compensation | | 97 |
| | 119 |
|
| Liabilities from risk management activities | | 10 |
| | 55 |
|
| Other regulatory liabilities, current | | 1 |
| | 240 |
|
| Other current liabilities | | 65 |
| | 39 |
|
| Total current liabilities | | 1,361 |
| | 1,595 |
|
| Long-term Debt | | 6,859 |
| | 6,654 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,505 |
| | 4,241 |
|
| Deferred credits related to income taxes | | 67 |
| | 70 |
|
| Accumulated deferred investment tax credits | | 112 |
| | 118 |
|
| Employee benefit obligations | | 366 |
| | 388 |
|
| Asset retirement obligations | | 1,501 |
| | 1,448 |
|
| Other cost of removal obligations | | 695 |
| | 722 |
|
| Other regulatory liabilities, deferred | | 95 |
| | 136 |
|
| Deferred over recovered regulatory clause revenues | | 157 |
| | — |
|
| Other deferred credits and liabilities | | 56 |
| | 76 |
|
| Total deferred credits and other liabilities | | 7,554 |
| | 7,199 |
|
| Total Liabilities | | 15,774 |
| | 15,448 |
|
| Redeemable Preferred Stock | | 85 |
| | 85 |
|
| Preference Stock | | 196 |
| | 196 |
|
| 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 | | 2,607 |
| | 2,341 |
|
| Retained earnings | | 2,604 |
| | 2,461 |
|
| Accumulated other comprehensive loss | | (31 | ) | | (32 | ) |
| Total common stockholder's equity | | 6,402 |
| | 5,992 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,457 |
| | $ | 21,721 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricityelectric service to retail and wholesale customers within its traditional service territory located withinin the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power'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 restoration following major storms. Alabama Power 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 Alabama Power for the foreseeable future.
Alabama Power continues to focus on several key performance indicators. These indicators includeincluding, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $55 | | 18.6 | | $52 | | 7.8 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) |
| (% change) |
| $18 | | 11.5 |
Alabama Power's net income after dividends on preferred and preference stock for the thirdfirst quarter 20162017 was $350$174 million compared to $295$156 million for the corresponding period in 2015.2016. The increase in net income was primarily related to an increase in revenue primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015, an increase in retail revenuesrates under Rate CNP Compliance,RSE effective January 1, 2017 and a decrease in non-fuel operations and maintenance expenses. These increasesThe increase to net income werewas partially offset by a decrease in AFUDC and an increaseweather-related revenues associated with milder weather in depreciation and amortization.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2016 was $717 million compared to $665 million for the corresponding period in 2015. The increase was primarily related to an increase in retail revenues under Rate CNP Compliance and decreases in non-fuel operations and maintenance expenses and dividends on preferred and preference stock for year-to-date 2016first quarter 2017 compared to the corresponding period in 2015. These increases to income were partially offset by a decrease in AFUDC and increases in interest expense and depreciation and amortization.2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $71 | | 4.6 | | $(12) | | (0.3) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $34 | | 2.8 |
In the thirdfirst quarter 2016,2017, retail revenues were $1.63$1.23 billion compared to $1.56$1.19 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $4.14 billion compared to $4.15 billion for the corresponding period in 2015.2016.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 |
| Year-to-Date 2016 | First Quarter 2017 |
| | (in millions) |
| (% change) |
| (in millions) |
| (% change) | (in millions) |
| (% change) |
| Retail – prior year | $ | 1,558 |
| | | | $ | 4,151 |
| | | $ | 1,193 |
| | |
| Estimated change resulting from – | | | | | | | | | | |
| Rates and pricing | 42 |
| | 2.7 |
| | 119 |
| | 2.9 |
| 80 |
| | 6.7 |
|
| Sales growth (decline) | (14 | ) | | (0.9 | ) | | (15 | ) | | (0.4 | ) | (1 | ) | | (0.1 | ) |
| Weather | 52 |
| | 3.4 |
| | 5 |
| | 0.1 |
| (55 | ) | | (4.6 | ) |
| Fuel and other cost recovery | (9 | ) | | (0.6 | ) | | (121 | ) | | (2.9 | ) | 10 |
| | 0.8 |
|
| Retail – current year | $ | 1,629 |
| | 4.6 | % | | $ | 4,139 |
| | (0.3 | )% | $ | 1,227 |
| | 2.8 | % |
Revenues associated with changes in rates and pricing increased in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 20152016 primarily due to increased revenuesan increase in rates under Rate CNP Compliance associated with increases in the average net investments.RSE effective January 1, 2017. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales declinedremained essentially flat in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 2015.2016. Industrial KWH sales decreased 6.3% and 5.1%1.2% for the thirdfirst quarter and year-to-date 2016, respectively,2017 when compared to the corresponding periodsperiod in 20152016 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growthpipeline sector, partially offset by an increase in the industrial sector.chemicals and paper sectors. Weather-adjusted commercial KWH sales decreased 1.2% for the first quarter 2017 due to lower customer usage. Weather-adjusted residential KWH sales decreased 2.4%increased 0.6% for the thirdfirst quarter 20162017 primarily due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth, and remained relatively flat year-to-date 2016. Weather-adjusted commercial KWH sales remained relatively flat for the third quarter and year-to-date 2016.growth.
Revenues resulting from changes in weather increaseddecreased in the thirdfirst quarter 20162017 due to warmermilder weather experienced in Alabama Power's service territory compared to the corresponding period in 2015.2016. For the thirdfirst quarter 2016,2017, the resulting increasesdecreases were 6.2%9.0% and 2.3%2.1% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues decreasedincreased in the thirdfirst quarter 20162017 when compared to the corresponding period in 20152016 primarily due to a decrease in the average cost of fuel. Fuel and other cost recovery revenues decreased year-to-date 2016 when compared to the corresponding period in 2015 primarily due to a decrease in KWH generation and a decreasean increase in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Affiliates
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $11 | | 50.0 |
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 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 Alabama Power's energy cost recovery clauses.
In the first quarter 2017, wholesale revenues from sales to affiliates were $33 million compared to $22 million for the corresponding period in 2016. The increase was primarily due to a 41.3% increase in KWH sales as a result of lower cost Alabama Power-owned generation as compared to the market cost of available energy and a 7.9% increase in the price of energy due to an increase in natural gas prices.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-AffiliatesFuel and Purchased Power Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 26.2 | | $23 | | 12.2 |
|
| | | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | 30 |
| | 11.2 |
|
| Purchased power – non-affiliates | (2 | ) | | (5.6 | ) |
| Purchased power – affiliates | (5 | ) | | (15.2 | ) |
| Total fuel and purchased power expenses | $ | 23 |
| | |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power'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 affect net income.
In the thirdfirst quarter 2016, wholesale revenues from sales to non-affiliates2017, fuel and purchased power expenses were $82$360 million compared to $65$337 million for the corresponding period in 2015.2016. The increase was primarily due to a 45.3%$41 million increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 13.4% decrease in the price of energy as a result of lower gas prices. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $211 million compared to $188 million for the corresponding period in 2015. The increase was primarily due to a 29.7% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 13.1% decrease in the price of energy as a result of lower gas prices.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | |
| | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 2 |
| | 0.5 | | $ | (88 | ) | | (8.3 | ) |
| Purchased power – non-affiliates | | 7 |
| | 12.5 | | (3 | ) | | (2.1 | ) |
| Purchased power – affiliates | | (10 | ) | | (19.6) | | (24 | ) | | (15.7 | ) |
| Total fuel and purchased power expenses | | $ | (1 | ) | | | | $ | (115 | ) | | |
For year-to-date 2016, fuel and purchased power expenses were $1.24 billion compared to $1.36 billion for the corresponding period in 2015. The decrease was primarily due to a $56 million decrease related to the average costvolume of fuel,KWHs generated and a $43$4 million decreasenet increase related to the average cost of purchased power and a $35 million decrease related to the volume of KWHs generated.fuel. These decreasesincreases were partially offset by a $19$22 million increasedecrease in 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 Alabama Power's energy cost recovery clause. Alabama Power, 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 of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Alabama Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 |
| Year-to-Date 2015 | First Quarter 2017 |
| First Quarter 2016 |
Total generation (in billions of KWHs) | 18 | | 17 | | 46 | | 46 | 15 | | 15 |
Total purchased power (in billions of KWHs) | 2 | | 2 | | 6 | | 5 | 1 | | 1 |
Sources of generation (percent) — | | |
| Coal | 59 | | 61 | | 51 | | 56 | 49 | | 40 |
| Nuclear | 22 | | 23 | | 24 | | 23 | 26 | | 27 |
| Gas | 18 | | 14 | | 19 | | 16 | 20 | | 19 |
| Hydro | 1 | | 2 | | 6 | | 5 | 5 | | 14 |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | 2.73 | | 2.79 | | 2.80 | | 2.85 | 2.60 | | 2.86 |
| Nuclear | 0.77 | | 0.81 | | 0.78 | | 0.81 | 0.74 | | 0.77 |
| Gas | 2.85 | | 3.11 | | 2.62 | | 3.08 | 2.77 | | 2.46 |
Average cost of fuel, generated (in cents per net KWH)(a) | 2.32 | | 2.39 | | 2.25 | | 2.40 | 2.13 | | 2.12 |
Average cost of purchased power (in cents per net KWH)(b) | 5.70 | | 6.90 | | 4.81 | | 5.56 | 6.70 | | 5.16 |
| |
(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 Alabama Power for tolling agreements where power is generated by the provider. |
Fuel
For year-to-date 2016,In the first quarter 2017, fuel expense was $0.97 billion$298 million compared to $1.06 billion$268 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to a 14.9% decrease23.1% increase in the volume of KWHs generated by coal and a 12.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 10.4% decrease in the volume of KWHs generated by coal, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the third quarter 2016, purchased power expense from non-affiliates was $63 million compared to $56 million for the corresponding period in 2015. The increase was primarily due to a 47.8% increase in the amount of energy purchased as a result of lower cost generation, partially offset by a 23.5%9.1% decrease in the average cost of purchased power per KHW due to a decrease in transmission capacity charges.
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
In the third quarter 2016, purchased power expense from affiliates was $41 million compared to $51 million for the corresponding period in 2015. The decrease was primarily due to a 14.4% decrease in the average cost of purchased powercoal per KWH as a result of lower capacity charges and a 4.4% decrease in the amount of energy purchased due to the availability of lower cost energy.
For year-to-date 2016, purchased power expense from affiliates was $129 million compared to $153 million for the corresponding period in 2015. The decrease was primarily related to a 17.3% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices.generated.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – Affiliates
In the first quarter 2017, purchased power expense from affiliates was $28 million compared to $33 million for the corresponding period in 2016. The decrease was primarily related to a 43.6% decrease in the amount of energy purchased as a result of decreased demand in 2017, partially offset by a 47.6% increase in the average cost of purchased power per KWH as a result of fixed natural gas transportation costs for Plant Gaston.
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
| | | Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 | |
| First Quarter 2017 vs. First Quarter 2016 | | First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | (% change) |
| $(23) | | (6.2) | | $(43) | | (3.8) | | (5.9) |
In the thirdfirst quarter 2016,2017, other operations and maintenance expenses were $348$369 million compared to $371$392 million for the corresponding period in 2015.2016. The decrease was primarily due to a net decreasedecreases of $8$23 million in employee compensation and benefits, including pension costs. In addition, scheduled other power generation outage costs and uncollectible customer account expenses decreased $8 million and $3 million, respectively.
For year-to-date 2016, other operations and maintenance expenses were $1.10 billion compared to $1.14 billion for the corresponding period in 2015. The decrease was primarily due to a net decrease of $22 million in employee compensation and benefits, including pension costs. In addition, scheduled steam and other power generation outage and labor costs and $3 million in nuclear generation costs primarily due to lower amortization of prior outage costs. In addition, bad debt expense decreased $18$2 million.
See Note (F) to the Condensed Financial Statements herein for additional information related to pension These decreases were partially offset by a $6 million increase in vegetation management costs.
Depreciation and AmortizationIncome Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 8.6 | | $43 | | 8.9 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $24 | | 23.5 |
In the thirdfirst quarter 2016, depreciation and amortization was $1772017, income taxes were $126 million compared to $163$102 million for the corresponding period in 2015. For year-to-date 2016, depreciation2016. The increase was primarily due to higher pre-tax earnings and amortization was $524 million comparedunrecognized tax benefits related to $481 millioncertain state deductions for federal income taxes.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the corresponding periodtimely 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 driven primarily 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. 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 2015. These increases wereAlabama Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the resultcorporate income tax rate, allowing 100% of an increasecapital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in depreciationItem 1A
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance related steam equipment.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 of Alabama Power under "Retail Regulatory Matters – Rate CNP"CNP Compliance" in Item 8 of the Form 10-K for additional information. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income TaxesEnvironmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
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 Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 5.5 | | $11 | | 4.0 |
of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.
Other Matters
Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power'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 by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Alabama Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the third quarterapplication of these policies, certain estimates are made that may have a material impact on Alabama Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Alabama Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Alabama Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
presented separately from revenues under ASC 606 on Alabama Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Alabama Power has not elected its transition method.
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 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 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. Alabama Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 taxesand 2017 and are expected to result in a decrease in operating income and an increase in other than income taxes were $96 million comparedfor 2018. The adoption of ASU 2017-07 is not expected to $91have a material impact on Alabama Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 2017. Alabama Power 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $128 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $286first three months of 2017, a decrease of $213 million as compared to $275the first three months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation and the timing of vendor payments. Net cash used for investing activities totaled $329 million for the corresponding period in 2015. These increases werefirst three months of 2017 primarily due to increases in stategross property additions related to distribution, transmission, environmental, and municipal utility license tax bases and increases in ad valorem taxessteam generation. Net cash provided from financing activities totaled $477 million for the first three months of 2017 primarily due to an increaseissuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt. Fluctuations in assessed valuecash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of property.securities.
Significant balance sheet changes for the first three months of 2017 include increases of $546 million in long-term debt, primarily due to the issuance of additional senior notes, $323 million in additional paid-in capital due to capital contributions from Southern Company, $276 million in cash and cash equivalents, and $121 million in property, plant, and equipment, primarily due to additions to environmental, transmission, steam generation, and distribution. Other significant changes include decreases of $201 million in other accounts payable primarily due to
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the timing of vendor payments, $200 million in securities due within one year, and $150 million in deferred under recovered regulatory clause revenues primarily due to the application of the Rate RSE refund liability and establishment of a separate regulatory asset to eliminate the under-recovered balance in Rate CNP PPA in accordance with the accounting order issued by the Alabama PSC. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $361 million will be required through March 31, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and " – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.
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 statutes 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.
Sources of Capital
Alabama Power 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, short-term debt, term loans, external security issuances, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power'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 March 31, 2017, Alabama Power had approximately $696 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Expires Within One Year |
| 2017 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) |
| $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
|
See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Alabama Power 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, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power 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 Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $890 million as of March 31, 2017. At March 31, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power 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 Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.
Details of commercial paper borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 30 |
| | 0.9 | % | | $ | 200 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017. |
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At March 31, 2017, Alabama Power 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at March 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 | $ | 316 |
|
Included in these amounts are certain agreements that could require collateral in the event that either 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 Alabama Power 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 Alabama Power) from stable to negative.
Financing Activities
In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.
In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power 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.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 1,689 |
| | $ | 1,717 |
|
| Wholesale revenues, non-affiliates | 39 |
| | 41 |
|
| Wholesale revenues, affiliates | 8 |
| | 5 |
|
| Other revenues | 96 |
| | 109 |
|
| Total operating revenues | 1,832 |
| | 1,872 |
|
| Operating Expenses: | | | |
| Fuel | 371 |
| | 376 |
|
| Purchased power, non-affiliates | 88 |
| | 83 |
|
| Purchased power, affiliates | 172 |
| | 139 |
|
| Other operations and maintenance | 381 |
| | 457 |
|
| Depreciation and amortization | 221 |
| | 211 |
|
| Taxes other than income taxes | 98 |
| | 97 |
|
| Total operating expenses | 1,331 |
| | 1,363 |
|
| Operating Income | 501 |
| | 509 |
|
| Other Income and (Expense): | | | |
| Interest expense, net of amounts capitalized | (101 | ) | | (94 | ) |
| Other income (expense), net | 20 |
| | 17 |
|
| Total other income and (expense) | (81 | ) | | (77 | ) |
| Earnings Before Income Taxes | 420 |
| | 432 |
|
| Income taxes | 156 |
| | 159 |
|
| Net Income | 264 |
| | 273 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 260 |
| | $ | 269 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income | $ | 264 |
| | $ | 273 |
|
| Other comprehensive income (loss): | | | |
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $-, respectively | — |
| | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
|
| Comprehensive Income | $ | 265 |
| | $ | 274 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 264 |
| | $ | 273 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 271 |
| | 261 |
|
| Deferred income taxes | 71 |
| | 55 |
|
| Allowance for equity funds used during construction | (13 | ) | | (14 | ) |
| Deferred expenses | 38 |
| | 38 |
|
| Pension, postretirement, and other employee benefits | (21 | ) | | (10 | ) |
| Settlement of asset retirement obligations | (22 | ) | | (24 | ) |
| Other, net | (29 | ) | | 27 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 142 |
| | 155 |
|
| -Fossil fuel stock | (38 | ) | | 36 |
|
| -Prepaid income taxes | 5 |
| | 38 |
|
| -Other current assets | (16 | ) | | 12 |
|
| -Accounts payable | (155 | ) | | 4 |
|
| -Accrued taxes | (235 | ) | | (235 | ) |
| -Accrued compensation | (87 | ) | | (66 | ) |
| -Retail fuel cost over recovery | (66 | ) | | 14 |
|
| -Other current liabilities | 2 |
| | 2 |
|
| Net cash provided from operating activities | 111 |
| | 566 |
|
| Investing Activities: | | | |
| Property additions | (556 | ) | | (553 | ) |
| Nuclear decommissioning trust fund purchases | (161 | ) | | (211 | ) |
| Nuclear decommissioning trust fund sales | 155 |
| | 206 |
|
| Cost of removal, net of salvage | (17 | ) | | (15 | ) |
| Change in construction payables, net of joint owner portion | (36 | ) | | (101 | ) |
| Payments pursuant to LTSAs | (22 | ) | | (11 | ) |
| Sale of property | 63 |
| | — |
|
| Other investing activities | 8 |
| | (4 | ) |
| Net cash used for investing activities | (566 | ) | | (689 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (391 | ) | | (158 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 345 |
| | 218 |
|
| Senior notes | 850 |
| | 650 |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | — |
| | (4 | ) |
| Senior notes | — |
| | (250 | ) |
| Payment of common stock dividends | (320 | ) | | (326 | ) |
| Other financing activities | (11 | ) | | (14 | ) |
| Net cash provided from financing activities | 473 |
| | 116 |
|
| Net Change in Cash and Cash Equivalents | 18 |
| | (7 | ) |
| Cash and Cash Equivalents at Beginning of Period | 3 |
| | 67 |
|
| Cash and Cash Equivalents at End of Period | $ | 21 |
| | $ | 60 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $5 and $5 capitalized for 2017 and 2016, respectively) | $ | 88 |
| | $ | 86 |
|
| Income taxes, net | (5 | ) | | (88 | ) |
| Noncash transactions — Accrued property additions at end of period | 320 |
| | 290 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 3 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 470 |
| | 523 |
|
| Unbilled revenues | | 200 |
| | 224 |
|
| Joint owner accounts receivable | | 146 |
| | 57 |
|
| Other accounts and notes receivable | | 57 |
| | 81 |
|
| Affiliated | | 12 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 336 |
| | 298 |
|
| Materials and supplies | | 474 |
| | 479 |
|
| Prepaid expenses | | 35 |
| | 105 |
|
| Other regulatory assets, current | | 195 |
| | 193 |
|
| Other current assets | | 38 |
| | 38 |
|
| Total current assets | | 1,981 |
| | 2,016 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 34,059 |
| | 33,841 |
|
| Less: Accumulated provision for depreciation | | 11,443 |
| | 11,317 |
|
| Plant in service, net of depreciation | | 22,616 |
| | 22,524 |
|
| Nuclear fuel, at amortized cost | | 570 |
| | 569 |
|
| Construction work in progress | | 5,183 |
| | 4,939 |
|
| Total property, plant, and equipment | | 28,369 |
| | 28,032 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 58 |
| | 60 |
|
| Nuclear decommissioning trusts, at fair value | | 853 |
| | 814 |
|
| Miscellaneous property and investments | | 46 |
| | 46 |
|
| Total other property and investments | | 957 |
| | 920 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 676 |
| | 676 |
|
| Other regulatory assets, deferred | | 2,792 |
| | 2,774 |
|
| Other deferred charges and assets | | 473 |
| | 417 |
|
| Total deferred charges and other assets | | 3,941 |
| | 3,867 |
|
| Total Assets | | $ | 35,248 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 488 |
| | $ | 460 |
|
| Notes payable | | — |
| | 391 |
|
| Accounts payable — | | | | |
| Affiliated | | 347 |
| | 438 |
|
| Other | | 657 |
| | 589 |
|
| Customer deposits | | 268 |
| | 265 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 56 |
| | 17 |
|
| Other accrued taxes | | 115 |
| | 390 |
|
| Accrued interest | | 115 |
| | 106 |
|
| Accrued compensation | | 110 |
| | 224 |
|
| Asset retirement obligations, current | | 305 |
| | 299 |
|
| Other current liabilities | | 241 |
| | 297 |
|
| Total current liabilities | | 2,702 |
| | 3,476 |
|
| Long-term Debt | | 11,042 |
| | 10,225 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,073 |
| | 6,000 |
|
| Deferred credits related to income taxes | | 119 |
| | 121 |
|
| Accumulated deferred investment tax credits | | 253 |
| | 256 |
|
| Employee benefit obligations | | 673 |
| | 703 |
|
| Asset retirement obligations, deferred | | 2,256 |
| | 2,233 |
|
| Other deferred credits and liabilities | | 214 |
| | 199 |
|
| Total deferred credits and other liabilities | | 9,588 |
| | 9,512 |
|
| Total Liabilities | | 23,332 |
| | 23,213 |
|
| Preferred Stock | | 45 |
| | 45 |
|
| Preference Stock | | 221 |
| | 221 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
|
| Paid-in capital | | 7,238 |
| | 6,885 |
|
| Retained earnings | | 4,026 |
| | 4,086 |
|
| Accumulated other comprehensive loss | | (12 | ) | | (13 | ) |
| Total common stockholder's equity | | 11,650 |
| | 11,356 |
|
| Total Liabilities and Stockholder's Equity | | $ | 35,248 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric 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 Georgia Power's business of 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, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Also on March 29, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Georgia Power 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(9) | | (3.3) |
Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2017 was $260 million compared to $269 million for the corresponding period in 2016. The decrease was primarily due to milder weather as compared to the corresponding period in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(28) | | (1.6) |
In the first quarter 2017, retail revenues were $1.69 billion compared to $1.72 billion for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 1,717 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 26 |
| | 1.5 |
|
| Sales decline | (12 | ) | | (0.7 | ) |
| Weather | (72 | ) | | (4.2 | ) |
| Fuel cost recovery | 30 |
| | 1.8 |
|
| Retail – current year | $ | 1,689 |
| | (1.6 | )% |
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to the rate pricing effect of decreased customer usage and higher contributions from commercial and industrial customers under a rate plan allowing for variable demand-driven pricing.
Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted residential KWH sales increased 1.3%, weather-adjusted commercial KWH sales decreased 2.5%, and weather-adjusted industrial KWH sales decreased 3.2% in the first quarter 2017 when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since March 31, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 1,400 commercial customers since March 31, 2016. Decreased demand in the chemicals, paper, transportation, and stone, clay, and glass sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the lumber and rubber sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $30 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to higher natural gas prices and less available hydro generation, partially offset by lower energy sales resulting from milder weather in the first quarter 2017 as compared to the corresponding period in 2016. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
Other Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(13) | | (11.9) |
In the first quarter 2017, other revenues were $96 million compared to $109 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment for customer temporary facilities services revenues in 2016, partially offset by a $4 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
|
| | | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | (5 | ) | | (1.3 | ) |
| Purchased power – non-affiliates | 5 |
| | 6.0 |
|
| Purchased power – affiliates | 33 |
| | 23.7 |
|
| Total fuel and purchased power expenses | $ | 33 |
| | |
In the first quarter 2017, total fuel and purchased power expenses were $631 million compared to $598 million in the corresponding period in 2016. The increase in the first quarter 2017 was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices and less rainfall for hydro generation, partially offset by a net decrease of $12 million related to the volume of KWHs generated and purchased due to milder weather as compared to the corresponding period in 2016 resulting in lower customer demand.
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 Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in billions of KWHs) | 14 | | 16 |
Total purchased power (in billions of KWHs) | 7 | | 6 |
Sources of generation (percent) — | | | |
| Coal | 27 | | 30 |
| Nuclear | 26 | | 23 |
| Gas | 45 | | 42 |
| Hydro | 2 | | 5 |
Cost of fuel, generated (in cents per net KWH) — | | | |
| Coal | 3.26 | | 3.56 |
| Nuclear | 0.85 | | 0.86 |
| Gas | 2.77 | | 2.01 |
Average cost of fuel, generated (in cents per net KWH) | 2.39 | | 2.22 |
Average cost of purchased power (in cents per net KWH)(*) | 4.47 | | 4.32 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the first quarter 2017, fuel expense was $371 million compared to $376 million in the corresponding period in 2016. The decrease was primarily due to a 21.1% decrease in the volume of KWHs generated by coal, partially offset by a 37.8% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the first quarter 2017, purchased power expense from non-affiliates was $88 million compared to $83 million in the corresponding period in 2016. The increase was not material. 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
In the first quarter 2017, purchased power expense from affiliates was $172 million compared to $139 million in the corresponding period in 2016. The increase was primarily the result of a 13.8% increase in the volume of KWHs purchased to meet customer demand and a 6.8% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.
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 purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(76) | | (16.6) |
In the first quarter 2017, other operations and maintenance expenses were $381 million compared to $457 million in the corresponding period in 2016. The decrease is primarily due to cost containment activities implemented in the third quarter 2016, a $19 million increase in gains from sales of integrated transmission system assets, and a $6 million decrease in demand-side management costs related to the timing of new programs. Cost containment activities contributed to decreases of $18 million in employee compensation and benefit costs, $14 million in generation maintenance costs, and $7 million in transmission and distribution overhead line maintenance.
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $10 | | 4.7 |
In the first quarter 2017, depreciation and amortization was $221 million compared to $211 million in the corresponding period in 2016. The increase was primarily related to additional plant in service.
Interest Expense, Net of Amounts Capitalized
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 7.4 |
In the first quarter 2017, interest expense, net of amounts capitalized was $101 million compared to $94 million in the corresponding period in 2016. The increase was primarily due to a $6 million increase in interest due to senior note issuances and additional long-term borrowings from the FFB.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings from the FFB.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power'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. The impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 is also a major factor. Future earnings will be driven primarily 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, increasing volumes of electronic commerce transactions, and higher multi-family home construction. 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 Georgia Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power'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. 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. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Regulatory Matters
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 tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing 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 tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
Vogtle 3 and 4 Agreement and Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.
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 litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.
Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
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 by including the related CWIP accounts in rate base during the construction period.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC on February 27, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.1 billion as of March 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs through March 31, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
As of March 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
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. Processes are in place
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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.
As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power'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 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 Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Georgia Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Georgia Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Georgia Power has not elected its transition method.
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 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 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. Georgia Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power'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 adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at March 31, 2017. Georgia Power 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $111 million for the first three months of 2017 compared to $566 million for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $566 million for the first three months of 2017 compared to $689 million for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $473 million for the first three months of 2017 compared to $116 million in the corresponding period in 2016. The increase in cash provided from financing activities is primarily due to higher issuances of senior notes, higher capital contributions received from Southern Company, and a maturity of senior notes in 2016, partially offset by a reduction in short-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first three months of 2017 include an increase in long-term debt of $845 million due to issuances of senior notes, a decrease in notes payable of $391 million primarily due to changes in short-term liquidity needs, an increase in paid-in capital of $353 million primarily due to capital contributions received from Southern Company, and an increase in property, plant, and equipment of $337 million to comply with environmental standards and construction of generation, transmission, and distribution facilities.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $488 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
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 statutes 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 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. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Georgia Power 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, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power has entered into a loan guarantee agreement (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. Eligible Project Costs incurred through March 31, 2017 would allow for borrowings of up to $2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At March 31, 2017, Georgia Power's current liabilities exceeded current assets by $721 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At March 31, 2017, Georgia Power had approximately $21 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at March 31, 2017 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.
This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Georgia Power was 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, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2017 was approximately $868 million. In addition, at March 31, 2017, Georgia Power had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Georgia Power 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 Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period (*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 152 |
| | 1.0 | % | | $ | 415 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At March 31, 2017, Georgia Power 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 Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at March 31, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,224 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama 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 Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
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 Georgia Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
Subsequent to March 31, 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Georgia Power may reoffer these bonds to the public at a later date.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power 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.
GULF POWER COMPANY
GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 279 |
| | $ | 283 |
|
| Wholesale revenues, non-affiliates | 17 |
| | 16 |
|
| Wholesale revenues, affiliates | 37 |
| | 21 |
|
| Other revenues | 17 |
| | 15 |
|
| Total operating revenues | 350 |
| | 335 |
|
| Operating Expenses: | | | |
| Fuel | 108 |
| | 94 |
|
| Purchased power, non-affiliates | 32 |
| | 30 |
|
| Purchased power, affiliates | 2 |
| | 2 |
|
| Other operations and maintenance | 84 |
| | 77 |
|
| Depreciation and amortization | 18 |
| | 38 |
|
| Taxes other than income taxes | 27 |
| | 29 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Total operating expenses | 304 |
| | 270 |
|
| Operating Income | 46 |
| | 65 |
|
| Other Income and (Expense): | | | |
| Interest expense, net of amounts capitalized | (12 | ) | | (13 | ) |
| Other income (expense), net | — |
| | (1 | ) |
| Total other income and (expense) | (12 | ) | | (14 | ) |
| Earnings Before Income Taxes | 34 |
| | 51 |
|
| Income taxes | 14 |
| | 20 |
|
| Net Income | 20 |
| | 31 |
|
| Dividends on Preference Stock | 2 |
| | 2 |
|
| Net Income After Dividends on Preference Stock | $ | 18 |
| | $ | 29 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income | $ | 20 |
| | $ | 31 |
|
| Other comprehensive income (loss): | | | |
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $(2), respectively | (1 | ) | | (3 | ) |
| Total other comprehensive income (loss) | (1 | ) | | (3 | ) |
| Comprehensive Income | $ | 19 |
| | $ | 28 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 20 |
| | $ | 31 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 20 |
| | 40 |
|
| Deferred income taxes | 5 |
| | 9 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Other, net | (2 | ) | | (1 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (1 | ) | | 35 |
|
| -Fossil fuel stock | 12 |
| | 15 |
|
| -Other current assets | 6 |
| | 2 |
|
| -Accrued taxes | (4 | ) | | 13 |
|
| -Accrued compensation | (23 | ) | | (18 | ) |
| -Over recovered regulatory clause revenues | (18 | ) | | 1 |
|
| -Other current liabilities | 2 |
| | 5 |
|
| Net cash provided from operating activities | 50 |
| | 132 |
|
| Investing Activities: | | | |
| Property additions | (46 | ) | | (32 | ) |
| Cost of removal, net of salvage | (2 | ) | | (2 | ) |
| Change in construction payables | (7 | ) | | (6 | ) |
| Other investing activities | (2 | ) | | (2 | ) |
| Net cash used for investing activities | (57 | ) | | (42 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (168 | ) | | (85 | ) |
| Proceeds — | | | |
| Common stock issued to parent | 175 |
| | — |
|
| Capital contributions from parent company | 4 |
| | 1 |
|
| Payment of common stock dividends | (31 | ) | | (30 | ) |
| Other financing activities | 3 |
| | (2 | ) |
| Net cash used for financing activities | (17 | ) | | (116 | ) |
| Net Change in Cash and Cash Equivalents | (24 | ) | | (26 | ) |
| Cash and Cash Equivalents at Beginning of Period | 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 32 |
| | $ | 48 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | $ | 2 |
| | $ | 3 |
|
| Income taxes, net | — |
| | (25 | ) |
| Noncash transactions — Accrued property additions at end of period | 26 |
| | 15 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 32 |
| | $ | 56 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 58 |
| | 72 |
|
| Unbilled revenues | | 52 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 47 |
| | 17 |
|
| Other accounts and notes receivable | | 9 |
| | 6 |
|
| Affiliated | | 28 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 59 |
| | 71 |
|
| Materials and supplies | | 56 |
| | 55 |
|
| Other regulatory assets, current | | 50 |
| | 44 |
|
| Other current assets | | 22 |
| | 30 |
|
| Total current assets | | 412 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,110 |
| | 5,140 |
|
| Less: Accumulated provision for depreciation | | 1,401 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,709 |
| | 3,758 |
|
| Construction work in progress | | 67 |
| | 51 |
|
| Total property, plant, and equipment | | 3,776 |
| | 3,809 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 57 |
| | 58 |
|
| Other regulatory assets, deferred | | 501 |
| | 512 |
|
| Other deferred charges and assets | | 21 |
| | 21 |
|
| Total deferred charges and other assets | | 579 |
| | 591 |
|
| Total Assets | | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 92 |
| | $ | 87 |
|
| Notes payable | | 100 |
| | 268 |
|
| Accounts payable — | | | | |
| Affiliated | | 47 |
| | 59 |
|
| Other | | 47 |
| | 54 |
|
| Customer deposits | | 35 |
| | 35 |
|
| Accrued taxes | | 16 |
| | 20 |
|
| Accrued interest | | 18 |
| | 8 |
|
| Accrued compensation | | 17 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Asset retirement obligations, current | | 32 |
| | 16 |
|
| Other regulatory liabilities, current | | 5 |
| | 16 |
|
| Other current liabilities | | 30 |
| | 24 |
|
| Total current liabilities | | 461 |
| | 649 |
|
| Long-term Debt | | 987 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 952 |
| | 948 |
|
| Employee benefit obligations | | 94 |
| | 96 |
|
| Deferred capacity expense | | 114 |
| | 119 |
|
| Asset retirement obligations | | 106 |
| | 120 |
|
| Other cost of removal obligations | | 226 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 48 |
| | 47 |
|
| Other deferred credits and liabilities | | 78 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,618 |
| | 1,650 |
|
| Total Liabilities | | 3,066 |
| | 3,286 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — March 31, 2017: 7,392,717 shares | | | | |
| — December 31, 2016: 5,642,717 shares | | 678 |
| | 503 |
|
| Paid-in capital | | 594 |
| | 589 |
|
| Retained earnings | | 282 |
| | 296 |
|
| Accumulated other comprehensive income | | — |
| | 1 |
|
| Total common stockholder's equity | | 1,554 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of 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, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power 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 Gulf Power for the foreseeable future.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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 rate approved by the Florida PSC in November 2016.
Gulf Power 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.
RESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (37.9) |
Gulf Power's net income after dividends on preference stock for the first quarter 2017 was $18 million compared to $29 million for the corresponding period in 2016. The decrease was primarily due to a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement, partially offset by a decrease in depreciation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(4) | | (1.4) |
In the first quarter 2017, retail revenues were $279 million compared to $283 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 283 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 1 |
| | 0.4 |
|
| Sales decline | (2 | ) | | (0.7 | ) |
| Weather | (5 | ) | | (1.8 | ) |
| Fuel and other cost recovery | 2 |
| | 0.7 |
|
| Retail – current year | $ | 279 |
| | (1.4 | )% |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in the environmental cost recovery clause resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. For the first quarter 2017, weather-adjusted KWH sales to residential and commercial customers decreased 1.5% and 0.7%, respectively, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 8.8% for the first quarter 2017 primarily due to increased customer co-generation.
Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to higher recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by lower recoverable costs under Gulf Power's fuel cost recovery and purchased power capacity cost recovery clauses. 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. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $16 | | 76.2 |
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 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 the first quarter 2017, wholesale revenues from sales to affiliates were $37 million compared to $21 million for the corresponding period in 2016. The increase was primarily due to a 55.4% increase in KWH sales resulting from increased generation as a result of system reliability requirements.
Fuel and Purchased Power Expenses
|
| | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | 14 |
| | 14.9 |
| Purchased power – non-affiliates | 2 |
| | 6.7 |
| Total fuel and purchased power expenses | $ | 16 |
| | |
In the first quarter 2017, total fuel and purchased power expenses were $142 million compared to $126 million for the corresponding period in 2016. The increase was primarily the result of a $10 million net increase related to the volume of KWHs generated and purchased due to higher generation from Gulf Power's coal-fired units and a $6 million net increase due to the higher average cost of fuel and purchased power for Gulf Power's gas-fired PPA resource.
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 Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 2,322 | | 1,816 |
Total purchased power (in millions of KWHs) | 1,459 | | 1,760 |
Sources of generation (percent) – | | | |
| Coal | 53 | | 42 |
| Gas | 47 | | 58 |
Cost of fuel, generated (in cents per net KWH) – | | | |
| Coal | 3.27 | | 3.92 |
| Gas | 3.24 | | 3.75 |
Average cost of fuel, generated (in cents per net KWH) | 3.26 | | 3.82 |
Average cost of purchased power (in cents per net KWH)(*) | 4.57 | | 3.22 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the first quarter 2017, fuel expense was $108 million compared to $94 million for the corresponding period in 2016. The increase was primarily due to a 60.9% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to system reliability requirements, partially offset by a 14.7% decrease in the average cost of fuel resulting from lower coal and natural gas prices.
Purchased Power – Non-Affiliates
In the first quarter 2017, purchased power expense from non-affiliates was $32 million compared to $30 million for the corresponding period in 2016. The increase was primarily due to a 39.0% increase in the average cost per KWH purchased primarily resulting from higher fuel costs associated with external purchases, partially offset by a 14.8% decrease in the volume of KWHs purchased due to increased Gulf Power 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 electric service territory, and the availability of the Southern Company system's generation.
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 9.1 |
In the first quarter 2017, other operations and maintenance expenses were $84 million compared to $77 million for the corresponding period in 2016. The increase was primarily due to expenses at generating facilities associated with environmental compliance and routine and planned maintenance.
Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(20) | | (52.6) |
In the first quarter 2017, depreciation and amortization was $18 million compared to $38 million for the corresponding period in 2016. The decrease was primarily due to $20 million more of a reduction in depreciation in the first quarter 2017 compared to the corresponding period in 2016, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement). See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Income Taxes
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(6) | | (30.0) |
In the first quarter 2017, income taxes were $14 million compared to $20 million for the corresponding period in 2016. This change was primarily due to the income tax benefit associated with the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Rate Case Settlement Agreement. This decrease was partially offset by higher pre-tax earnings, excluding the write-down. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf Power'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 driven primarily 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 due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a variety 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 Gulf Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
basis or through market-based contracts. 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. Gulf Power'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 legislative or regulatory 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 adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power'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 base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement 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 may not 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 the first quarter 2017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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, 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 rate approved by the Florida PSC in November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power'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.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power'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 by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGulf Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Gulf Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Gulf Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Gulf Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Gulf Power has not elected its transition method.
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 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
income statement. The capitalization of 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. Gulf Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power'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 adoption of ASU 2017-07 is not expected to have a material impact on Gulf Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at March 31, 2017. Gulf Power 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $50 million for the first three months of 2017 compared to $132 million for the corresponding period in 2016. The $82 million decrease in net cash was primarily due to a federal income tax refund received in 2016, as well as decreases in cash flows associated with accrued taxes, cost recovery clauses as a result of decreased revenue collection, and changes in accounts receivable in 2017 compared to 2016. Net cash used for investing activities totaled $57 million in the first three months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $17 million for the first three months of 2017 primarily due to a decrease in notes payable and the payment of common stock dividends, partially offset by proceeds from the issuance of common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first three months of 2017 include an increase in common stock of $175 million, a decrease in notes payable of $168 million, primarily funded with the common stock issuance, and a decrease in property, plant, and equipment primarily due to the write-down of Gulf Power's ownership of Plant Scherer Unit 3. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $92 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Financing Activities" herein 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 statutes 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 programs; 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Gulf Power plans to obtain the funds required to 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, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued 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. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
At March 31, 2017, Gulf Power had approximately $32 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) |
| $ | 85 |
| | $ | 195 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 25 |
| | $ | 70 |
|
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Gulf Power 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, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power 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 Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2017 was approximately $82 million. In addition, at March 31, 2017, Gulf Power had approximately $86 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Gulf Power 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 Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. 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 in the balance sheets.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at March 31, 2017 | | 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) |
| Commercial paper | | $ | — |
| | — | % | | $ | 29 |
| | 1.1 | % | | $ | 168 |
|
| Short-term bank debt | | 100 |
| | 1.7 | % | | 100 |
| | 1.5 | % | | 100 |
|
| Total | | $ | 100 |
| | 1.7 | % | | $ | 129 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
Credit Rating Risk
At March 31, 2017, Gulf Power 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 Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, transmission, and energy price risk management.
The maximum potential collateral requirements under these contracts at March 31, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 564 |
|
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 Gulf Power 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 Gulf Power) from stable to negative.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity had been limited because its long-term sales agreements shifted substantially all fuel cost responsibility to the purchaser. However, Gulf Power is exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolves the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power 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. In particular, Gulf Power may, subject to applicable market conditions, call for redemption and refinance all or a portion of its $150 million aggregate outstanding preference stock during 2017.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 200 |
| | $ | 183 |
|
| Wholesale revenues, non-affiliates | 62 |
| | 60 |
|
| Wholesale revenues, affiliates | 5 |
| | 9 |
|
| Other revenues | 5 |
| | 5 |
|
| Total operating revenues | 272 |
| | 257 |
|
| Operating Expenses: | | | |
| Fuel | 78 |
| | 76 |
|
| Purchased power, non-affiliates | 1 |
| | — |
|
| Purchased power, affiliates | 7 |
| | 5 |
|
| Other operations and maintenance | 74 |
| | 69 |
|
| Depreciation and amortization | 40 |
| | 38 |
|
| Taxes other than income taxes | 26 |
| | 26 |
|
| Estimated loss on Kemper IGCC | 108 |
| | 53 |
|
| Total operating expenses | 334 |
| | 267 |
|
| Operating Loss | (62 | ) | | (10 | ) |
| Other Income and (Expense): | | | |
| Allowance for equity funds used during construction | 35 |
| | 29 |
|
| Interest expense, net of amounts capitalized | (19 | ) | | (16 | ) |
| Other income (expense), net | (1 | ) | | (2 | ) |
| Total other income and (expense) | 15 |
| | 11 |
|
| Earnings (Loss) Before Income Taxes | (47 | ) | | 1 |
|
| Income taxes (benefit) | (27 | ) | | (10 | ) |
| Net Income (Loss) | (20 | ) | | 11 |
|
| Dividends on Preferred Stock | — |
| | — |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | (20 | ) | | $ | 11 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income (Loss) | $ | (20 | ) | | $ | 11 |
|
| Other comprehensive income (loss) |
| |
|
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $-, respectively | 1 |
| | — |
|
| Total other comprehensive income (loss) | 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | (19 | ) | | $ | 11 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | (20 | ) | | $ | 11 |
|
| Adjustments to reconcile net income to net cash used for operating activities — | | | |
| Depreciation and amortization, total | 49 |
| | 39 |
|
| Deferred income taxes | (47 | ) | | (4 | ) |
| Allowance for equity funds used during construction | (35 | ) | | (29 | ) |
| Estimated loss on Kemper IGCC | 108 |
| | 53 |
|
| Other, net | (3 | ) | | (4 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Other current assets | 18 |
| | 43 |
|
| -Accounts payable | (35 | ) | | (22 | ) |
| -Accrued taxes | (46 | ) | | (60 | ) |
| -Accrued compensation | (22 | ) | | (16 | ) |
| -Over recovered regulatory clause revenues | (12 | ) | | 9 |
|
| -Customer liability associated with Kemper refunds | — |
| | (51 | ) |
| -Other current liabilities | 5 |
| | 8 |
|
| Net cash used for operating activities | (40 | ) | | (23 | ) |
| Investing Activities: | | | |
| Property additions | (186 | ) | | (197 | ) |
| Construction payables | — |
| | (7 | ) |
| Payments pursuant to LTSAs | 1 |
| | (5 | ) |
| Other investing activities | (5 | ) | | (5 | ) |
| Net cash used for investing activities | (190 | ) | | (214 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 9 |
| | — |
|
| Proceeds — | | | |
| Long-term debt to parent company | — |
| | 200 |
|
| Other long-term debt | — |
| | 900 |
|
| Short-term borrowings | 4 |
| | — |
|
| Redemptions — | | | |
| Short-term borrowings | — |
| | (475 | ) |
| Other long-term debt | — |
| | (425 | ) |
| Other financing activities | (1 | ) | | (2 | ) |
| Net cash provided from financing activities | 12 |
| | 198 |
|
| Net Change in Cash and Cash Equivalents | (218 | ) | | (39 | ) |
| Cash and Cash Equivalents at Beginning of Period | 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 6 |
| | $ | 59 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $25 and $22, net of $12 and $10 capitalized for 2017
and 2016, respectively) | $ | 13 |
| | $ | 12 |
|
| Income taxes, net | — |
| | (24 | ) |
| Noncash transactions — Accrued property additions at end of period | 78 |
| | 97 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 6 |
| | $ | 224 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 26 |
| | 29 |
|
| Unbilled revenues | | 38 |
| | 42 |
|
| Income taxes receivable, current | | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 17 |
| | 14 |
|
| Affiliated | | 14 |
| | 15 |
|
| Fossil fuel stock | | 83 |
| | 100 |
|
| Materials and supplies | | 78 |
| | 76 |
|
| Other regulatory assets, current | | 113 |
| | 115 |
|
| Other current assets | | 3 |
| | 8 |
|
| Total current assets | | 922 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,963 |
| | 4,865 |
|
| Less: Accumulated provision for depreciation | | 1,303 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,660 |
| | 3,576 |
|
| Construction work in progress | | 2,570 |
| | 2,545 |
|
| Total property, plant, and equipment | | 6,230 |
| | 6,121 |
|
| Other Property and Investments | | 12 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 382 |
| | 361 |
|
| Other regulatory assets, deferred | | 520 |
| | 518 |
|
| Other deferred charges and assets | | 22 |
| | 56 |
|
| Total deferred charges and other assets | | 924 |
| | 935 |
|
| Total Assets | | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year — | | | | |
| Parent | | $ | — |
| | $ | 551 |
|
| Other | | 1,328 |
| | 78 |
|
| Notes payable | | 36 |
| | 23 |
|
| Accounts payable — | | | | |
| Affiliated | | 44 |
| | 62 |
|
| Other | | 112 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes | | 51 |
| | 99 |
|
| Unrecognized tax benefits | | 385 |
| | 383 |
|
| Accrued interest | | 50 |
| | 46 |
|
| Accrued compensation | | 20 |
| | 42 |
|
| Asset retirement obligations, current | | 27 |
| | 32 |
|
| Over recovered regulatory clause liabilities | | 39 |
| | 51 |
|
| Other current liabilities | | 22 |
| | 20 |
|
| Total current liabilities | | 2,130 |
| | 1,538 |
|
| Long-term Debt: | | | | |
| Long-term debt to parent | | 551 |
| | — |
|
| Long-term debt, non-affiliated | | 1,172 |
| | 2,424 |
|
| Total Long-term Debt | | 1,723 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 729 |
| | 756 |
|
| Employee benefit obligations | | 113 |
| | 115 |
|
| Asset retirement obligations, deferred | | 148 |
| | 146 |
|
| Other cost of removal obligations | | 172 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 78 |
| | 84 |
|
| Other deferred credits and liabilities | | 36 |
| | 26 |
|
| Total deferred credits and other liabilities | | 1,276 |
| | 1,297 |
|
| Total Liabilities | | 5,129 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 1,130,000 shares | | | | |
| Outstanding — 1,121,000 shares | | 38 |
| | 38 |
|
| Paid-in capital | | 3,526 |
| | 3,525 |
|
| Accumulated deficit | | (635 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 2,926 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric 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 Mississippi Power's business of providing electric service. These factors include Mississippi Power'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 the Kemper IGCC, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
Mississippi Power continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC 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 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).
The current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. 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 Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. Upon placing the remainder of the plant in service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.
Mississippi Power is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale MRA rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
In connection with the 2017 Rate Case, Mississippi Power expects to request authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of these matters cannot now be determined but could result in further charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
In addition to the construction, start-up, and rate recovery of the Kemper IGCC, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(31) | | N/M |
N/M - Not meaningful
Mississippi Power's net loss after dividends on preferred stock for the first quarter 2017 was $20 million compared to net income of $11 million for the corresponding period in 2016. The decrease in net income was primarily related to higher pre-tax charges of $108 million ($67 million after tax) in 2017 compared to pre-tax charges of $53 million ($33 million after tax) in 2016 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was partially offset by an increase in operating revenues and AFUDC equity.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $17 | | 9.3 |
In the first quarter 2017, retail revenues were $200 million compared to $183 million for the corresponding period in 2016.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 183 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 12 |
| | 6.6 |
|
| Sales growth (decline) | 4 |
| | 2.1 |
|
| Weather | (5 | ) | | (2.7 | ) |
| Fuel and other cost recovery | 6 |
| | 3.3 |
|
| Retail – current year | $ | 200 |
| | 9.3 | % |
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to an ECO Plan rate increase implemented in the third quarter 2016.
Revenues attributable to changes in sales increased for the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 1.3% due to higher customer usage offset by a decline in the number of customers. Weather-adjusted KWH sales to commercial customers decreased 0.1% due to lower customer usage offset by customer growth. KWH sales to industrial customers increased 0.6% primarily due to an unplanned outage by a large customer in 2016.
Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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.
Wholesale Revenues – Affiliates
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(4) | | (44.4) |
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 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 the first quarter 2017, wholesale revenues from sales to affiliates were $5 million compared to $9 million for the corresponding period in 2016. The decrease was due to a $5 million decrease in KWH sales primarily due to the availability of lower cost alternatives offset by a $1 million increase associated with higher natural gas prices.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | 2 |
| | 2.6 |
| Purchased power – non-affiliates | 1 |
| | N/M |
| Purchased power – affiliates | 2 |
| | 40.0 |
| Total fuel and purchased power expenses | $ | 5 |
| | |
N/M - Not meaningful
In the first quarter 2017, total fuel and purchased power expenses were $86 million compared to $81 million for the corresponding period in 2016. The increase was due to a $15 million increase in natural gas prices offset by a $10 million net decrease in the volume of KWHs generated and 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 Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 3,161 | | 3,588 |
Total purchased power (in millions of KWHs) | 242 | | 261 |
Sources of generation (percent) – | | | |
| Coal | 9 | | 11 |
| Gas | 91 | | 89 |
Cost of fuel, generated (in cents per net KWH) – | | | |
| Coal | 3.33 | | 3.55 |
| Gas | 2.65 | | 2.15 |
Average cost of fuel, generated (in cents per net KWH) | 2.71 | | 2.32 |
Average cost of purchased power (in cents per net KWH) | 3.33 | | 2.17 |
Fuel
In the first quarter 2017, total fuel expense was $78 million compared to $76 million for the corresponding period in 2016. The increase was due to a 17% increase in the average cost of fuel per KWH generated primarily due to a 23% higher cost of natural gas offset by a 12% decrease in the volume of KWHs generated primarily as a result of lower sales.
Purchased Power - Affiliates
In the first quarter 2017, purchased power expense from affiliates was $7 million compared to $5 million for the corresponding period in 2016. The increase was primarily due to a 35% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost, partially offset by a 6% decrease in the average cost per KWH purchased primarily as a result of lower fuel prices.
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 purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $5 | | 7.2 |
In the first quarter 2017, other operations and maintenance expenses were $74 million compared to $69 million for the corresponding period in 2016. The increase was primarily due to a $3 million increase in amortization of prior operations and maintenance expense deferrals associated with the Kemper IGCC in-service assets and a $2 million increase in generation maintenance expenses, including scheduled outages.
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.
Estimated Loss on Kemper IGCC
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $55 | | N/M |
N/M - Not meaningful
In the first quarters of 2017 and 2016, estimated probable losses on the Kemper IGCC of $108 million and $53 million, respectively, were recorded at Mississippi Power. These losses reflect 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 the Initial DOE Grants and excluding the Cost Cap Exceptions.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During ConstructionGEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (50.0) | | $(20) | | (46.5) |
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 1,689 |
| | $ | 1,717 |
|
| Wholesale revenues, non-affiliates | 39 |
| | 41 |
|
| Wholesale revenues, affiliates | 8 |
| | 5 |
|
| Other revenues | 96 |
| | 109 |
|
| Total operating revenues | 1,832 |
| | 1,872 |
|
| Operating Expenses: | | | |
| Fuel | 371 |
| | 376 |
|
| Purchased power, non-affiliates | 88 |
| | 83 |
|
| Purchased power, affiliates | 172 |
| | 139 |
|
| Other operations and maintenance | 381 |
| | 457 |
|
| Depreciation and amortization | 221 |
| | 211 |
|
| Taxes other than income taxes | 98 |
| | 97 |
|
| Total operating expenses | 1,331 |
| | 1,363 |
|
| Operating Income | 501 |
| | 509 |
|
| Other Income and (Expense): | | | |
| Interest expense, net of amounts capitalized | (101 | ) | | (94 | ) |
| Other income (expense), net | 20 |
| | 17 |
|
| Total other income and (expense) | (81 | ) | | (77 | ) |
| Earnings Before Income Taxes | 420 |
| | 432 |
|
| Income taxes | 156 |
| | 159 |
|
| Net Income | 264 |
| | 273 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 260 |
| | $ | 269 |
|
In the third quarter 2016, AFUDC equity was $7 million compared to $14 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $23 million compared to $43 million for the corresponding period in 2015. These decreases were primarily associated with environmental compliance and steam generation capital projects being placed in service in 2016.Interest Expense, Net of Amounts CapitalizedCONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 8.5 | | $19 | | 9.3 |
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income | $ | 264 |
| | $ | 273 |
|
| Other comprehensive income (loss): | | | |
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $-, respectively | — |
| | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 1 |
|
| Comprehensive Income | $ | 265 |
| | $ | 274 |
|
In the third quarter 2016, interest expense, netThe accompanying notes as they relate to Georgia Power are an integral part of amounts capitalized was $77 million comparedthese condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 264 |
| | $ | 273 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 271 |
| | 261 |
|
| Deferred income taxes | 71 |
| | 55 |
|
| Allowance for equity funds used during construction | (13 | ) | | (14 | ) |
| Deferred expenses | 38 |
| | 38 |
|
| Pension, postretirement, and other employee benefits | (21 | ) | | (10 | ) |
| Settlement of asset retirement obligations | (22 | ) | | (24 | ) |
| Other, net | (29 | ) | | 27 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 142 |
| | 155 |
|
| -Fossil fuel stock | (38 | ) | | 36 |
|
| -Prepaid income taxes | 5 |
| | 38 |
|
| -Other current assets | (16 | ) | | 12 |
|
| -Accounts payable | (155 | ) | | 4 |
|
| -Accrued taxes | (235 | ) | | (235 | ) |
| -Accrued compensation | (87 | ) | | (66 | ) |
| -Retail fuel cost over recovery | (66 | ) | | 14 |
|
| -Other current liabilities | 2 |
| | 2 |
|
| Net cash provided from operating activities | 111 |
| | 566 |
|
| Investing Activities: | | | |
| Property additions | (556 | ) | | (553 | ) |
| Nuclear decommissioning trust fund purchases | (161 | ) | | (211 | ) |
| Nuclear decommissioning trust fund sales | 155 |
| | 206 |
|
| Cost of removal, net of salvage | (17 | ) | | (15 | ) |
| Change in construction payables, net of joint owner portion | (36 | ) | | (101 | ) |
| Payments pursuant to LTSAs | (22 | ) | | (11 | ) |
| Sale of property | 63 |
| | — |
|
| Other investing activities | 8 |
| | (4 | ) |
| Net cash used for investing activities | (566 | ) | | (689 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (391 | ) | | (158 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 345 |
| | 218 |
|
| Senior notes | 850 |
| | 650 |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | — |
| | (4 | ) |
| Senior notes | — |
| | (250 | ) |
| Payment of common stock dividends | (320 | ) | | (326 | ) |
| Other financing activities | (11 | ) | | (14 | ) |
| Net cash provided from financing activities | 473 |
| | 116 |
|
| Net Change in Cash and Cash Equivalents | 18 |
| | (7 | ) |
| Cash and Cash Equivalents at Beginning of Period | 3 |
| | 67 |
|
| Cash and Cash Equivalents at End of Period | $ | 21 |
| | $ | 60 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $5 and $5 capitalized for 2017 and 2016, respectively) | $ | 88 |
| | $ | 86 |
|
| Income taxes, net | (5 | ) | | (88 | ) |
| Noncash transactions — Accrued property additions at end of period | 320 |
| | 290 |
|
The accompanying notes as they relate to $71 million for the corresponding period in 2015. The increase was primarily due toGeorgia Power are an increase in debt outstanding and a reduction in amounts capitalized.integral part of these condensed financial statements.
For year-to-date 2016, interest expense, net of amounts capitalized was $224 million compared to $205 million for the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized. See "Allowance for Equity Funds Used During Construction" herein, FUTURE EARNINGS POTENTIAL – "Financing Activities – Financial Condition and Liquidity" herein, and Note 6 to the financial statements of Alabama Power under "Senior Notes" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), NetGEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 28.6 | | $8 | | 33.3 |
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 21 |
| | $ | 3 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 470 |
| | 523 |
|
| Unbilled revenues | | 200 |
| | 224 |
|
| Joint owner accounts receivable | | 146 |
| | 57 |
|
| Other accounts and notes receivable | | 57 |
| | 81 |
|
| Affiliated | | 12 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 336 |
| | 298 |
|
| Materials and supplies | | 474 |
| | 479 |
|
| Prepaid expenses | | 35 |
| | 105 |
|
| Other regulatory assets, current | | 195 |
| | 193 |
|
| Other current assets | | 38 |
| | 38 |
|
| Total current assets | | 1,981 |
| | 2,016 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 34,059 |
| | 33,841 |
|
| Less: Accumulated provision for depreciation | | 11,443 |
| | 11,317 |
|
| Plant in service, net of depreciation | | 22,616 |
| | 22,524 |
|
| Nuclear fuel, at amortized cost | | 570 |
| | 569 |
|
| Construction work in progress | | 5,183 |
| | 4,939 |
|
| Total property, plant, and equipment | | 28,369 |
| | 28,032 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 58 |
| | 60 |
|
| Nuclear decommissioning trusts, at fair value | | 853 |
| | 814 |
|
| Miscellaneous property and investments | | 46 |
| | 46 |
|
| Total other property and investments | | 957 |
| | 920 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 676 |
| | 676 |
|
| Other regulatory assets, deferred | | 2,792 |
| | 2,774 |
|
| Other deferred charges and assets | | 473 |
| | 417 |
|
| Total deferred charges and other assets | | 3,941 |
| | 3,867 |
|
| Total Assets | | $ | 35,248 |
| | $ | 34,835 |
|
For year-to-date 2016, other income (expense), net was $(16) million comparedThe accompanying notes as they relate to $(24) million for the corresponding period in 2015. The change was primarily due to a decrease in donations, partially offset by a decrease in salesGeorgia Power are an integral part of non-utility property in 2016.these condensed financial statements.
Income Taxes
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 15.1 | | $39 | | 9.1 |
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 488 |
| | $ | 460 |
|
| Notes payable | | — |
| | 391 |
|
| Accounts payable — | | | | |
| Affiliated | | 347 |
| | 438 |
|
| Other | | 657 |
| | 589 |
|
| Customer deposits | | 268 |
| | 265 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 56 |
| | 17 |
|
| Other accrued taxes | | 115 |
| | 390 |
|
| Accrued interest | | 115 |
| | 106 |
|
| Accrued compensation | | 110 |
| | 224 |
|
| Asset retirement obligations, current | | 305 |
| | 299 |
|
| Other current liabilities | | 241 |
| | 297 |
|
| Total current liabilities | | 2,702 |
| | 3,476 |
|
| Long-term Debt | | 11,042 |
| | 10,225 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 6,073 |
| | 6,000 |
|
| Deferred credits related to income taxes | | 119 |
| | 121 |
|
| Accumulated deferred investment tax credits | | 253 |
| | 256 |
|
| Employee benefit obligations | | 673 |
| | 703 |
|
| Asset retirement obligations, deferred | | 2,256 |
| | 2,233 |
|
| Other deferred credits and liabilities | | 214 |
| | 199 |
|
| Total deferred credits and other liabilities | | 9,588 |
| | 9,512 |
|
| Total Liabilities | | 23,332 |
| | 23,213 |
|
| Preferred Stock | | 45 |
| | 45 |
|
| Preference Stock | | 221 |
| | 221 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — 9,261,500 shares | | 398 |
| | 398 |
|
| Paid-in capital | | 7,238 |
| | 6,885 |
|
| Retained earnings | | 4,026 |
| | 4,086 |
|
| Accumulated other comprehensive loss | | (12 | ) | | (13 | ) |
| Total common stockholder's equity | | 11,650 |
| | 11,356 |
|
| Total Liabilities and Stockholder's Equity | | $ | 35,248 |
| | $ | 34,835 |
|
In the third quarter 2016, income taxes were $221 million comparedThe accompanying notes as they relate to $192 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016.
For year-to-date 2016, income taxes were $466 million compared to $427 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings and state tax credits taken in 2015.Georgia Power are an integral part of these condensed financial statements.
ALABAMAGEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric 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 Georgia Power's business of 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, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Also on March 29, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Georgia Power 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Dividends on Preferred and Preference StockRESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $(8) | | (38.1) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(9) | | (3.3) |
For year-to-date 2016,Georgia Power's net income after dividends on preferred and preference stock were $13for the first quarter 2017 was $260 million compared to $21$269 million for the corresponding period in 2015. This2016. The decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6milder weather as compared to the financial statementscorresponding period in 2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(28) | | (1.6) |
In the first quarter 2017, retail revenues were $1.69 billion compared to $1.72 billion for the corresponding period in 2016.
Details of Alabama Powerthe changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 1,717 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 26 |
| | 1.5 |
|
| Sales decline | (12 | ) | | (0.7 | ) |
| Weather | (72 | ) | | (4.2 | ) |
| Fuel cost recovery | 30 |
| | 1.8 |
|
| Retail – current year | $ | 1,689 |
| | (1.6 | )% |
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to the rate pricing effect of decreased customer usage and higher contributions from commercial and industrial customers under "Redeemable Preferreda rate plan allowing for variable demand-driven pricing.
Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted residential KWH sales increased 1.3%, weather-adjusted commercial KWH sales decreased 2.5%, and Preference Stock"weather-adjusted industrial KWH sales decreased 3.2% in the first quarter 2017 when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since March 31, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 1,400 commercial customers since March 31, 2016. Decreased demand in the chemicals, paper, transportation, and stone, clay, and glass sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the lumber and rubber sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $30 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to higher natural gas prices and less available hydro generation, partially offset by lower energy sales resulting from milder weather in the first quarter 2017 as compared to the corresponding period in 2016. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 87 of the Form 10-K for additional information.
Other Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(13) | | (11.9) |
In the first quarter 2017, other revenues were $96 million compared to $109 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment for customer temporary facilities services revenues in 2016, partially offset by a $4 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
|
| | | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | (5 | ) | | (1.3 | ) |
| Purchased power – non-affiliates | 5 |
| | 6.0 |
|
| Purchased power – affiliates | 33 |
| | 23.7 |
|
| Total fuel and purchased power expenses | $ | 33 |
| | |
In the first quarter 2017, total fuel and purchased power expenses were $631 million compared to $598 million in the corresponding period in 2016. The increase in the first quarter 2017 was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices and less rainfall for hydro generation, partially offset by a net decrease of $12 million related to the volume of KWHs generated and purchased due to milder weather as compared to the corresponding period in 2016 resulting in lower customer demand.
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 Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in billions of KWHs) | 14 | | 16 |
Total purchased power (in billions of KWHs) | 7 | | 6 |
Sources of generation (percent) — | | | |
| Coal | 27 | | 30 |
| Nuclear | 26 | | 23 |
| Gas | 45 | | 42 |
| Hydro | 2 | | 5 |
Cost of fuel, generated (in cents per net KWH) — | | | |
| Coal | 3.26 | | 3.56 |
| Nuclear | 0.85 | | 0.86 |
| Gas | 2.77 | | 2.01 |
Average cost of fuel, generated (in cents per net KWH) | 2.39 | | 2.22 |
Average cost of purchased power (in cents per net KWH)(*) | 4.47 | | 4.32 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the first quarter 2017, fuel expense was $371 million compared to $376 million in the corresponding period in 2016. The decrease was primarily due to a 21.1% decrease in the volume of KWHs generated by coal, partially offset by a 37.8% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the first quarter 2017, purchased power expense from non-affiliates was $88 million compared to $83 million in the corresponding period in 2016. The increase was not material. 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
In the first quarter 2017, purchased power expense from affiliates was $172 million compared to $139 million in the corresponding period in 2016. The increase was primarily the result of a 13.8% increase in the volume of KWHs purchased to meet customer demand and a 6.8% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.
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 purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(76) | | (16.6) |
In the first quarter 2017, other operations and maintenance expenses were $381 million compared to $457 million in the corresponding period in 2016. The decrease is primarily due to cost containment activities implemented in the third quarter 2016, a $19 million increase in gains from sales of integrated transmission system assets, and a $6 million decrease in demand-side management costs related to the timing of new programs. Cost containment activities contributed to decreases of $18 million in employee compensation and benefit costs, $14 million in generation maintenance costs, and $7 million in transmission and distribution overhead line maintenance.
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $10 | | 4.7 |
In the first quarter 2017, depreciation and amortization was $221 million compared to $211 million in the corresponding period in 2016. The increase was primarily related to additional plant in service.
Interest Expense, Net of Amounts Capitalized
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 7.4 |
In the first quarter 2017, interest expense, net of amounts capitalized was $101 million compared to $94 million in the corresponding period in 2016. The increase was primarily due to a $6 million increase in interest due to senior note issuances and additional long-term borrowings from the FFB.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings from the FFB.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of AlabamaGeorgia Power's future earnings potential. The level of AlabamaGeorgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of AlabamaGeorgia Power's primary business of selling electricity.providing electric service. These factors include AlabamaGeorgia Power'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. The impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 is also a major factor. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, 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. 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 AlabamaGeorgia Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of AlabamaGeorgia Power in Item 7 of the Form 10-K.10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power'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. 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 of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of AlabamaGeorgia Power in Item 7 and Note 3 to the financial statements of AlabamaGeorgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of AlabamaGeorgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule regional haze regulations,revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its supplemental finding regarding considerationplanned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of coststhese matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in supportItem 7 of the MATS rule. This finding does not impact MATS ruleForm 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
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compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
FERC Matters
See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama Power's hydroelectric developments on the Coosa River. On April 21, 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request of the new license for Alabama Power's seven hydroelectric developments on the Coosa River. The order also denied rehearing requests filed by Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission. On May 17, 2016, Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a petition for review by the U.S. Court of Appeals for the District of Columbia Circuit. On September 12, 2016, the FERC issued an order denying the second rehearing request, and Alabama Rivers Alliance and American Rivers filed an appeal of the April 21, 2016 order to the U.S. Court of Appeals for the District of Columbia Circuit. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
AlabamaGeorgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the AlabamaGeorgia PSC. AlabamaGeorgia Power currently recovers its costs from the regulated retail business primarily through its Rate RSE, Rate CNP Compliance, rate energythe 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing 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 tariff. See "Nuclear Construction" herein and rate natural disaster reserve. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 andNote 3 to the financial statements of AlabamaGeorgia Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters" respectively, – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balancethe NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of each regulatory clausethe Form 10-K for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.additional information regarding fuel cost recovery.
Environmental Accounting OrderIntegrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Environmental Accounting Order"Integrated Resource Plan" of AlabamaGeorgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.
On March 7, 2017, the environmental accounting order.Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
In April 2016, as part of its environmental compliance strategy, Alabama Power 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.
RenewablesNuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL –Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Renewables" of Alabama PowerNuclear Construction" in Item 78 of the Form 10-K for additional information regarding renewable energy projects.the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
Vogtle 3 and 4 Agreement and Contractor Bankruptcy
In accordance2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Alabama PSC order approving upContractor, pursuant to 500 MWswhich the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement). Under the terms of renewable projects, Alabamathe 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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributable to Georgia Power has(based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.
On December 31, 2015, Westinghouse and the Vogtle Owners entered into agreementsa definitive settlement agreement (Contractor Settlement Agreement) to purchase power from orresolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to build renewable generation sources, including a 72-MW solar PPA approvedthe Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. TheDecember 31, 2018 for Unit 3 and December 31, 2019 for
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Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.
Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the
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Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
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 by including the related CWIP accounts in rate base during the construction period.
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On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the renewable agreements permit Alabama PowerVogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to usecalculate the energyNCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and retire$5.440 billion will also be 10.00% and the associated RECsROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its customers or to sell RECs, separately or bundledsixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with energy.the Georgia PSC on February 27, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.1 billion as of March 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs through March 31, 2017.
The ultimate outcome of these matters cannot be determined at this time.
Other Matters
AlabamaAs of March 31, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.
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. Processes are in place
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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 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.
As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. See additional risks in Item 1A herein regarding the Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, AlabamaGeorgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power'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 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 Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
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Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Georgia Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Georgia Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Georgia Power has not elected its transition method.
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 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 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. Georgia Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power'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 adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at March 31, 2017. Georgia Power 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
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"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $111 million for the first three months of 2017 compared to $566 million for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $566 million for the first three months of 2017 compared to $689 million for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $473 million for the first three months of 2017 compared to $116 million in the corresponding period in 2016. The increase in cash provided from financing activities is primarily due to higher issuances of senior notes, higher capital contributions received from Southern Company, and a maturity of senior notes in 2016, partially offset by a reduction in short-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first three months of 2017 include an increase in long-term debt of $845 million due to issuances of senior notes, a decrease in notes payable of $391 million primarily due to changes in short-term liquidity needs, an increase in paid-in capital of $353 million primarily due to capital contributions received from Southern Company, and an increase in property, plant, and equipment of $337 million to comply with environmental standards and construction of generation, transmission, and distribution facilities.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $488 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
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 statutes 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 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. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Georgia Power 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, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power has entered into a loan guarantee agreement (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. Eligible Project Costs incurred through March 31, 2017 would allow for borrowings of up to $2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At March 31, 2017, Georgia Power's current liabilities exceeded current assets by $721 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At March 31, 2017, Georgia Power had approximately $21 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at March 31, 2017 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.
This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Georgia Power was 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, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2017 was approximately $868 million. In addition, at March 31, 2017, Georgia Power had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Georgia Power 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 Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period (*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 152 |
| | 1.0 | % | | $ | 415 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017. |
Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
At March 31, 2017, Georgia Power 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 Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at March 31, 2017 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,224 |
|
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama 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 Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
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 Georgia Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
Subsequent to March 31, 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Georgia Power may reoffer these bonds to the public at a later date.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power 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.
GULF POWER COMPANY
GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 279 |
| | $ | 283 |
|
| Wholesale revenues, non-affiliates | 17 |
| | 16 |
|
| Wholesale revenues, affiliates | 37 |
| | 21 |
|
| Other revenues | 17 |
| | 15 |
|
| Total operating revenues | 350 |
| | 335 |
|
| Operating Expenses: | | | |
| Fuel | 108 |
| | 94 |
|
| Purchased power, non-affiliates | 32 |
| | 30 |
|
| Purchased power, affiliates | 2 |
| | 2 |
|
| Other operations and maintenance | 84 |
| | 77 |
|
| Depreciation and amortization | 18 |
| | 38 |
|
| Taxes other than income taxes | 27 |
| | 29 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Total operating expenses | 304 |
| | 270 |
|
| Operating Income | 46 |
| | 65 |
|
| Other Income and (Expense): | | | |
| Interest expense, net of amounts capitalized | (12 | ) | | (13 | ) |
| Other income (expense), net | — |
| | (1 | ) |
| Total other income and (expense) | (12 | ) | | (14 | ) |
| Earnings Before Income Taxes | 34 |
| | 51 |
|
| Income taxes | 14 |
| | 20 |
|
| Net Income | 20 |
| | 31 |
|
| Dividends on Preference Stock | 2 |
| | 2 |
|
| Net Income After Dividends on Preference Stock | $ | 18 |
| | $ | 29 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income | $ | 20 |
| | $ | 31 |
|
| Other comprehensive income (loss): | | | |
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $(2), respectively | (1 | ) | | (3 | ) |
| Total other comprehensive income (loss) | (1 | ) | | (3 | ) |
| Comprehensive Income | $ | 19 |
| | $ | 28 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 20 |
| | $ | 31 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 20 |
| | 40 |
|
| Deferred income taxes | 5 |
| | 9 |
|
| Loss on Plant Scherer Unit 3 | 33 |
| | — |
|
| Other, net | (2 | ) | | (1 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (1 | ) | | 35 |
|
| -Fossil fuel stock | 12 |
| | 15 |
|
| -Other current assets | 6 |
| | 2 |
|
| -Accrued taxes | (4 | ) | | 13 |
|
| -Accrued compensation | (23 | ) | | (18 | ) |
| -Over recovered regulatory clause revenues | (18 | ) | | 1 |
|
| -Other current liabilities | 2 |
| | 5 |
|
| Net cash provided from operating activities | 50 |
| | 132 |
|
| Investing Activities: | | | |
| Property additions | (46 | ) | | (32 | ) |
| Cost of removal, net of salvage | (2 | ) | | (2 | ) |
| Change in construction payables | (7 | ) | | (6 | ) |
| Other investing activities | (2 | ) | | (2 | ) |
| Net cash used for investing activities | (57 | ) | | (42 | ) |
| Financing Activities: | | | |
| Decrease in notes payable, net | (168 | ) | | (85 | ) |
| Proceeds — | | | |
| Common stock issued to parent | 175 |
| | — |
|
| Capital contributions from parent company | 4 |
| | 1 |
|
| Payment of common stock dividends | (31 | ) | | (30 | ) |
| Other financing activities | 3 |
| | (2 | ) |
| Net cash used for financing activities | (17 | ) | | (116 | ) |
| Net Change in Cash and Cash Equivalents | (24 | ) | | (26 | ) |
| Cash and Cash Equivalents at Beginning of Period | 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 32 |
| | $ | 48 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | $ | 2 |
| | $ | 3 |
|
| Income taxes, net | — |
| | (25 | ) |
| Noncash transactions — Accrued property additions at end of period | 26 |
| | 15 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 32 |
| | $ | 56 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 58 |
| | 72 |
|
| Unbilled revenues | | 52 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 47 |
| | 17 |
|
| Other accounts and notes receivable | | 9 |
| | 6 |
|
| Affiliated | | 28 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 59 |
| | 71 |
|
| Materials and supplies | | 56 |
| | 55 |
|
| Other regulatory assets, current | | 50 |
| | 44 |
|
| Other current assets | | 22 |
| | 30 |
|
| Total current assets | | 412 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,110 |
| | 5,140 |
|
| Less: Accumulated provision for depreciation | | 1,401 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,709 |
| | 3,758 |
|
| Construction work in progress | | 67 |
| | 51 |
|
| Total property, plant, and equipment | | 3,776 |
| | 3,809 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 57 |
| | 58 |
|
| Other regulatory assets, deferred | | 501 |
| | 512 |
|
| Other deferred charges and assets | | 21 |
| | 21 |
|
| Total deferred charges and other assets | | 579 |
| | 591 |
|
| Total Assets | | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 92 |
| | $ | 87 |
|
| Notes payable | | 100 |
| | 268 |
|
| Accounts payable — | | | | |
| Affiliated | | 47 |
| | 59 |
|
| Other | | 47 |
| | 54 |
|
| Customer deposits | | 35 |
| | 35 |
|
| Accrued taxes | | 16 |
| | 20 |
|
| Accrued interest | | 18 |
| | 8 |
|
| Accrued compensation | | 17 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Asset retirement obligations, current | | 32 |
| | 16 |
|
| Other regulatory liabilities, current | | 5 |
| | 16 |
|
| Other current liabilities | | 30 |
| | 24 |
|
| Total current liabilities | | 461 |
| | 649 |
|
| Long-term Debt | | 987 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 952 |
| | 948 |
|
| Employee benefit obligations | | 94 |
| | 96 |
|
| Deferred capacity expense | | 114 |
| | 119 |
|
| Asset retirement obligations | | 106 |
| | 120 |
|
| Other cost of removal obligations | | 226 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 48 |
| | 47 |
|
| Other deferred credits and liabilities | | 78 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,618 |
| | 1,650 |
|
| Total Liabilities | | 3,066 |
| | 3,286 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — March 31, 2017: 7,392,717 shares | | | | |
| — December 31, 2016: 5,642,717 shares | | 678 |
| | 503 |
|
| Paid-in capital | | 594 |
| | 589 |
|
| Retained earnings | | 282 |
| | 296 |
|
| Accumulated other comprehensive income | | — |
| | 1 |
|
| Total common stockholder's equity | | 1,554 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of 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, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power 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 Gulf Power for the foreseeable future.
On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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 rate approved by the Florida PSC in November 2016.
Gulf Power 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.
RESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (37.9) |
Gulf Power's net income after dividends on preference stock for the first quarter 2017 was $18 million compared to $29 million for the corresponding period in 2016. The decrease was primarily due to a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement, partially offset by a decrease in depreciation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(4) | | (1.4) |
In the first quarter 2017, retail revenues were $279 million compared to $283 million for the corresponding period in 2016.
Details of the changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 283 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 1 |
| | 0.4 |
|
| Sales decline | (2 | ) | | (0.7 | ) |
| Weather | (5 | ) | | (1.8 | ) |
| Fuel and other cost recovery | 2 |
| | 0.7 |
|
| Retail – current year | $ | 279 |
| | (1.4 | )% |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in the environmental cost recovery clause resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. For the first quarter 2017, weather-adjusted KWH sales to residential and commercial customers decreased 1.5% and 0.7%, respectively, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 8.8% for the first quarter 2017 primarily due to increased customer co-generation.
Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to higher recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by lower recoverable costs under Gulf Power's fuel cost recovery and purchased power capacity cost recovery clauses. 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. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $16 | | 76.2 |
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 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 the first quarter 2017, wholesale revenues from sales to affiliates were $37 million compared to $21 million for the corresponding period in 2016. The increase was primarily due to a 55.4% increase in KWH sales resulting from increased generation as a result of system reliability requirements.
Fuel and Purchased Power Expenses
|
| | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | 14 |
| | 14.9 |
| Purchased power – non-affiliates | 2 |
| | 6.7 |
| Total fuel and purchased power expenses | $ | 16 |
| | |
In the first quarter 2017, total fuel and purchased power expenses were $142 million compared to $126 million for the corresponding period in 2016. The increase was primarily the result of a $10 million net increase related to the volume of KWHs generated and purchased due to higher generation from Gulf Power's coal-fired units and a $6 million net increase due to the higher average cost of fuel and purchased power for Gulf Power's gas-fired PPA resource.
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 Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 2,322 | | 1,816 |
Total purchased power (in millions of KWHs) | 1,459 | | 1,760 |
Sources of generation (percent) – | | | |
| Coal | 53 | | 42 |
| Gas | 47 | | 58 |
Cost of fuel, generated (in cents per net KWH) – | | | |
| Coal | 3.27 | | 3.92 |
| Gas | 3.24 | | 3.75 |
Average cost of fuel, generated (in cents per net KWH) | 3.26 | | 3.82 |
Average cost of purchased power (in cents per net KWH)(*) | 4.57 | | 3.22 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the first quarter 2017, fuel expense was $108 million compared to $94 million for the corresponding period in 2016. The increase was primarily due to a 60.9% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to system reliability requirements, partially offset by a 14.7% decrease in the average cost of fuel resulting from lower coal and natural gas prices.
Purchased Power – Non-Affiliates
In the first quarter 2017, purchased power expense from non-affiliates was $32 million compared to $30 million for the corresponding period in 2016. The increase was primarily due to a 39.0% increase in the average cost per KWH purchased primarily resulting from higher fuel costs associated with external purchases, partially offset by a 14.8% decrease in the volume of KWHs purchased due to increased Gulf Power 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 electric service territory, and the availability of the Southern Company system's generation.
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 9.1 |
In the first quarter 2017, other operations and maintenance expenses were $84 million compared to $77 million for the corresponding period in 2016. The increase was primarily due to expenses at generating facilities associated with environmental compliance and routine and planned maintenance.
Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(20) | | (52.6) |
In the first quarter 2017, depreciation and amortization was $18 million compared to $38 million for the corresponding period in 2016. The decrease was primarily due to $20 million more of a reduction in depreciation in the first quarter 2017 compared to the corresponding period in 2016, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement). See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
Income Taxes
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(6) | | (30.0) |
In the first quarter 2017, income taxes were $14 million compared to $20 million for the corresponding period in 2016. This change was primarily due to the income tax benefit associated with the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Rate Case Settlement Agreement. This decrease was partially offset by higher pre-tax earnings, excluding the write-down. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf Power'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 driven primarily 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 due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior. Earnings are subject to a variety 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 Gulf Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
basis or through market-based contracts. 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. Gulf Power'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 legislative or regulatory 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 adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power'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 base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement 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 may not 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 the first quarter 2017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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, 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 rate approved by the Florida PSC in November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power'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.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power'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 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 AlabamaGulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofAlabama PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
have a material effect on AlabamaGulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
AlabamaGulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of AlabamaGulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on AlabamaGulf Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of AlabamaGulf Power in Item 7 of the Form 10-K for a complete discussion of AlabamaGulf Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Gulf Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Gulf Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Gulf Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Gulf Power has not elected its transition method.
On February 25, 2016,March 10, 2017, the FASB issued ASU No. 2016-02,2017-07, Leases(Topic 842)Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2016-02)2017-07). ASU 2016-022017-07 requires lessees to recognize onthat an employer report the balance sheet a lease liabilityservice cost component in the same line item or items as other compensation costs and a right-of-use asset for all leases. ASU 2016-02 also changesrequires the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certainother 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, with early adoption permitted. Alabama Power is currently evaluating the new standardnet periodic pension and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expectedpostretirement benefit costs to have a significant impact on Alabama Power's balance sheet.
On March 30, 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. Most significantly, 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 benefitbe separately presented in the income statement. Alabama Power currently recognizes any excess tax benefitsstatement outside 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 deficiencies related to the exerciseother components of net periodic pension and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Earlypostretirement benefit costs in the
ALABAMAGULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
adoptionincome statement. The capitalization of 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 permittedeffective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Gulf Power is currently evaluating the new standard. The presentation changes required for net periodic pension and Alabama Power intendspostretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to adopt the ASUresult in the fourth quarter 2016.a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on the results of operations,Gulf Power's financial position, or cash flows of Alabama Power.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of AlabamaGulf Power in Item 7 of the Form 10-K for additional information. AlabamaGulf Power's financial condition remained stable at September 30, 2016. AlabamaMarch 31, 2017. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangementsagreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $1.5 billion$50 million for the first ninethree months of 2016, a decrease of $44 million as2017 compared to $132 million for the first nine months of 2015.corresponding period in 2016. The $82 million decrease in net cash provided from operating activities was primarily due to lower fuela federal income tax refund received in 2016, as well as decreases in cash flows associated with accrued taxes, cost recovery revenues during 2016, partially offset by lower income tax payments and the receipt of income tax refundsclauses as a result of bonus depreciation.decreased revenue collection, and changes in accounts receivable in 2017 compared to 2016. Net cash used for investing activities totaled $1.1 billion for$57 million in the first ninethree months of 20162017 primarily due to gross property additions related to environmental, distribution, steam generation, and transmission.utility plant. Net cash used for financing activities totaled $91$17 million for the first ninethree months of 20162017 primarily due to a decrease in notes payable and the payment of common stock dividend payments and a redemption of long-term debt,dividends, partially offset by issuancesproceeds from the issuance of long-term debt and additional capital contributions from Southern Company.common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include increasesan increase in common stock of $422$175 million, a decrease in notes payable of $168 million, primarily funded with the common stock issuance, and a decrease in property, plant, and equipment primarily due to additions to environmental, distribution, nuclear generation, and transmission, $362 million in cash and cash equivalents, $266 million in additional paid-in capital due to capital contributions from Southern Company, $264 million in accumulated deferred income taxes related to bonus depreciation, and $205 million in long-term debt primarily duethe write-down of Gulf Power's ownership of Plant Scherer Unit 3. See Note (B) to the issuance of additional senior notes. Other significant changes include decreases of $239 million in other regulatory liabilities, current, primarily due to the timing of fuel cost recovery and $177 million in other accounts payable primarily due to the timing of vendor payments.
See Note 3 to the financial statements of AlabamaCondensed Financial Statements under "Regulatory Matters – Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K – Retail Base Rate Cases" herein for additional information regarding Alabama Power's rate mechanisms.information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of AlabamaGulf Power in Item 7 of the Form 10-K for a description of AlabamaGulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $236$92 million will be required through September 30, 2017March 31, 2018 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" and "Financing Activities" – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-Kherein for additional information on Alabama Power's environmental compliance strategy.
Alabama Power's approved construction program is currently estimated to total $1.9 billion for 2017, $1.6 billion for 2018, $1.2 billion for 2019, $1.3 billion for 2020, and $1.2 billion for 2021. 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 statutes and
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
regulations included in these amounts are $0.5 billion for 2017, $0.3 billion for 2018, $0.1 billion for 2019, $0.1 billion for 2020, and $0.2 billion for 2021. These estimated expenditures include anticipated costs for compliance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) and the EPA's final effluent guidelines rule. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit COinformation.2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
Alabama Power 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 Alabama Power's asset retirement obligation liabilities. These costs, which will change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance, are estimated to be $31 million for 2017, $26 million for 2018, $100 million for 2019, $105 million for 2020, and $107 million for 2021. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K 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; storm impacts; changes in environmental statutes 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;programs; changes in FERC rules and regulations; AlabamaFlorida 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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
AlabamaGulf Power plans to obtain the funds required 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, term loans, 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, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of AlabamaGulf Power in Item 7 of the Form 10-K for additional information.
AlabamaGulf Power's current liabilities sometimesfrequently exceed current assets because of long-term debt maturities and the periodiccontinued 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. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
At September 30, 2016, AlabamaMarch 31, 2017, Gulf Power had approximately $556$32 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016March 31, 2017 were as follows:
| | | Expires | Expires | | | | | | Due Within One Year | Expires | | | | | | Executable Term Loans | | Expires Within One Year |
| 2017 | 2017 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out | 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 35 |
| | $ | 500 |
| | $ | 800 |
| | $ | 1,335 |
| | $ | 1,335 |
| | $ | — |
| | $ | 35 |
| 85 |
| | $ | 195 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 25 |
| | $ | 70 |
|
See Note 6 to the financial statements of AlabamaGulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of AlabamaGulf Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Gulf Power defaulted on indebtedness, the payment of which was then accelerated. AlabamaAt March 31, 2017, Gulf Power 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, AlabamaGulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, AlabamaGulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portionMost of the unused credit arrangements with banks isare allocated to provide liquidity support to AlabamaGulf Power's pollution control revenue bonds and commercial paper borrowings.program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016March 31, 2017 was approximately $890$82 million. In addition, at September 30, 2016, AlabamaMarch 31, 2017, Gulf Power had $87approximately $86 million of fixed rate pollution control revenue bonds outstanding that were required to be reofferedremarketed within the next 12 months.
Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. AlabamaGulf Power 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 AlabamaGulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of AlabamaGulf Power are loaned directly to AlabamaGulf Power. 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 in the balance sheets.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period(*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 15 |
| | 0.6 | % | | $ | 100 |
|
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at March 31, 2017 | | 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) |
| Commercial paper | | $ | — |
| | — | % | | $ | 29 |
| | 1.1 | % | | $ | 168 |
|
| Short-term bank debt | | 100 |
| | 1.7 | % | | 100 |
| | 1.5 | % | | 100 |
|
| Total | | $ | 100 |
| | 1.7 | % | | $ | 129 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.March 31, 2017. |
AlabamaGulf Power believes the need for working capital can be adequately met by utilizing the commercial paper programs,program, lines of credit, short-term bank notes,loans, and operating cash flows.
Credit Rating Risk
AlabamaAt March 31, 2017, Gulf Power 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 BBBBBB- and/or Baa2Baa3 or below. These contracts are primarily for physical electricity purchases fuel purchases,and sales, fuel transportation and storage, transmission, and energy price risk management, and transmission. management.
The maximum potential collateral requirements under these contracts at September 30, 2016March 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 | $ | 347 |
|
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | |
| Credit Ratings | Maximum Potential Collateral Requirements |
| | (in millions) |
| At BBB- and/or Baa3 | $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 564 |
|
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 AlabamaGulf Power 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 Gulf Power) from stable to negative.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity had been limited because its long-term sales agreements shifted substantially all fuel cost responsibility to the purchaser. However, Gulf Power is exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolves the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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.
For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.
Financing Activities
In January 2016, Alabama2017, Gulf Power issued $400 million aggregate principal amount1,750,000 shares of Series 2016A 4.30% Senior Notes due January 2, 2046.common stock to Southern Company and realized proceeds of $175 million. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including AlabamaGulf Power's continuous construction program.
In March 2016, Alabama2017, Gulf Power entered into threeextended the maturity of a $100 million short-term floating rate bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bearbearing interest based on three-month LIBOR.one-month LIBOR from April 2017 to October 2017.
In addition to any financings that may be necessary to meet capital requirements, and contractual obligations, Alabamaand storm recovery, Gulf Power 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. In particular, Gulf Power may, subject to applicable market conditions, call for redemption and refinance all or a portion of its $150 million aggregate outstanding preference stock during 2017.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Revenues: | | | |
| Retail revenues | $ | 200 |
| | $ | 183 |
|
| Wholesale revenues, non-affiliates | 62 |
| | 60 |
|
| Wholesale revenues, affiliates | 5 |
| | 9 |
|
| Other revenues | 5 |
| | 5 |
|
| Total operating revenues | 272 |
| | 257 |
|
| Operating Expenses: | | | |
| Fuel | 78 |
| | 76 |
|
| Purchased power, non-affiliates | 1 |
| | — |
|
| Purchased power, affiliates | 7 |
| | 5 |
|
| Other operations and maintenance | 74 |
| | 69 |
|
| Depreciation and amortization | 40 |
| | 38 |
|
| Taxes other than income taxes | 26 |
| | 26 |
|
| Estimated loss on Kemper IGCC | 108 |
| | 53 |
|
| Total operating expenses | 334 |
| | 267 |
|
| Operating Loss | (62 | ) | | (10 | ) |
| Other Income and (Expense): | | | |
| Allowance for equity funds used during construction | 35 |
| | 29 |
|
| Interest expense, net of amounts capitalized | (19 | ) | | (16 | ) |
| Other income (expense), net | (1 | ) | | (2 | ) |
| Total other income and (expense) | 15 |
| | 11 |
|
| Earnings (Loss) Before Income Taxes | (47 | ) | | 1 |
|
| Income taxes (benefit) | (27 | ) | | (10 | ) |
| Net Income (Loss) | (20 | ) | | 11 |
|
| Dividends on Preferred Stock | — |
| | — |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | (20 | ) | | $ | 11 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Net Income (Loss) | $ | (20 | ) | | $ | 11 |
|
| Other comprehensive income (loss) |
| |
|
| Qualifying hedges: | | | |
| Changes in fair value, net of tax of $- and $-, respectively | 1 |
| | — |
|
| Total other comprehensive income (loss) | 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | (19 | ) | | $ | 11 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) |
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | (20 | ) | | $ | 11 |
|
| Adjustments to reconcile net income to net cash used for operating activities — | | | |
| Depreciation and amortization, total | 49 |
| | 39 |
|
| Deferred income taxes | (47 | ) | | (4 | ) |
| Allowance for equity funds used during construction | (35 | ) | | (29 | ) |
| Estimated loss on Kemper IGCC | 108 |
| | 53 |
|
| Other, net | (3 | ) | | (4 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Other current assets | 18 |
| | 43 |
|
| -Accounts payable | (35 | ) | | (22 | ) |
| -Accrued taxes | (46 | ) | | (60 | ) |
| -Accrued compensation | (22 | ) | | (16 | ) |
| -Over recovered regulatory clause revenues | (12 | ) | | 9 |
|
| -Customer liability associated with Kemper refunds | — |
| | (51 | ) |
| -Other current liabilities | 5 |
| | 8 |
|
| Net cash used for operating activities | (40 | ) | | (23 | ) |
| Investing Activities: | | | |
| Property additions | (186 | ) | | (197 | ) |
| Construction payables | — |
| | (7 | ) |
| Payments pursuant to LTSAs | 1 |
| | (5 | ) |
| Other investing activities | (5 | ) | | (5 | ) |
| Net cash used for investing activities | (190 | ) | | (214 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 9 |
| | — |
|
| Proceeds — | | | |
| Long-term debt to parent company | — |
| | 200 |
|
| Other long-term debt | — |
| | 900 |
|
| Short-term borrowings | 4 |
| | — |
|
| Redemptions — | | | |
| Short-term borrowings | — |
| | (475 | ) |
| Other long-term debt | — |
| | (425 | ) |
| Other financing activities | (1 | ) | | (2 | ) |
| Net cash provided from financing activities | 12 |
| | 198 |
|
| Net Change in Cash and Cash Equivalents | (218 | ) | | (39 | ) |
| Cash and Cash Equivalents at Beginning of Period | 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 6 |
| | $ | 59 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $25 and $22, net of $12 and $10 capitalized for 2017
and 2016, respectively) | $ | 13 |
| | $ | 12 |
|
| Income taxes, net | — |
| | (24 | ) |
| Noncash transactions — Accrued property additions at end of period | 78 |
| | 97 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 6 |
| | $ | 224 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 26 |
| | 29 |
|
| Unbilled revenues | | 38 |
| | 42 |
|
| Income taxes receivable, current | | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 17 |
| | 14 |
|
| Affiliated | | 14 |
| | 15 |
|
| Fossil fuel stock | | 83 |
| | 100 |
|
| Materials and supplies | | 78 |
| | 76 |
|
| Other regulatory assets, current | | 113 |
| | 115 |
|
| Other current assets | | 3 |
| | 8 |
|
| Total current assets | | 922 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,963 |
| | 4,865 |
|
| Less: Accumulated provision for depreciation | | 1,303 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,660 |
| | 3,576 |
|
| Construction work in progress | | 2,570 |
| | 2,545 |
|
| Total property, plant, and equipment | | 6,230 |
| | 6,121 |
|
| Other Property and Investments | | 12 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 382 |
| | 361 |
|
| Other regulatory assets, deferred | | 520 |
| | 518 |
|
| Other deferred charges and assets | | 22 |
| | 56 |
|
| Total deferred charges and other assets | | 924 |
| | 935 |
|
| Total Assets | | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year — | | | | |
| Parent | | $ | — |
| | $ | 551 |
|
| Other | | 1,328 |
| | 78 |
|
| Notes payable | | 36 |
| | 23 |
|
| Accounts payable — | | | | |
| Affiliated | | 44 |
| | 62 |
|
| Other | | 112 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes | | 51 |
| | 99 |
|
| Unrecognized tax benefits | | 385 |
| | 383 |
|
| Accrued interest | | 50 |
| | 46 |
|
| Accrued compensation | | 20 |
| | 42 |
|
| Asset retirement obligations, current | | 27 |
| | 32 |
|
| Over recovered regulatory clause liabilities | | 39 |
| | 51 |
|
| Other current liabilities | | 22 |
| | 20 |
|
| Total current liabilities | | 2,130 |
| | 1,538 |
|
| Long-term Debt: | | | | |
| Long-term debt to parent | | 551 |
| | — |
|
| Long-term debt, non-affiliated | | 1,172 |
| | 2,424 |
|
| Total Long-term Debt | | 1,723 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 729 |
| | 756 |
|
| Employee benefit obligations | | 113 |
| | 115 |
|
| Asset retirement obligations, deferred | | 148 |
| | 146 |
|
| Other cost of removal obligations | | 172 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 78 |
| | 84 |
|
| Other deferred credits and liabilities | | 36 |
| | 26 |
|
| Total deferred credits and other liabilities | | 1,276 |
| | 1,297 |
|
| Total Liabilities | | 5,129 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 1,130,000 shares | | | | |
| Outstanding — 1,121,000 shares | | 38 |
| | 38 |
|
| Paid-in capital | | 3,526 |
| | 3,525 |
|
| Accumulated deficit | | (635 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 2,926 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FIRST QUARTER 2017 vs. FIRST QUARTER 2016
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric 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 Mississippi Power's business of providing electric service. These factors include Mississippi Power'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 the Kemper IGCC, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
Mississippi Power continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC 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 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).
The current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. 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 Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. Upon placing the remainder of the plant in service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.
Mississippi Power is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale MRA rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
In connection with the 2017 Rate Case, Mississippi Power expects to request authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of these matters cannot now be determined but could result in further charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
In addition to the construction, start-up, and rate recovery of the Kemper IGCC, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(31) | | N/M |
N/M - Not meaningful
Mississippi Power's net loss after dividends on preferred stock for the first quarter 2017 was $20 million compared to net income of $11 million for the corresponding period in 2016. The decrease in net income was primarily related to higher pre-tax charges of $108 million ($67 million after tax) in 2017 compared to pre-tax charges of $53 million ($33 million after tax) in 2016 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was partially offset by an increase in operating revenues and AFUDC equity.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Retail Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $17 | | 9.3 |
In the first quarter 2017, retail revenues were $200 million compared to $183 million for the corresponding period in 2016.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
|
| | | | | | |
| | First Quarter 2017 |
| | (in millions) | | (% change) |
| Retail – prior year | $ | 183 |
| | |
| Estimated change resulting from – | | | |
| Rates and pricing | 12 |
| | 6.6 |
|
| Sales growth (decline) | 4 |
| | 2.1 |
|
| Weather | (5 | ) | | (2.7 | ) |
| Fuel and other cost recovery | 6 |
| | 3.3 |
|
| Retail – current year | $ | 200 |
| | 9.3 | % |
Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to an ECO Plan rate increase implemented in the third quarter 2016.
Revenues attributable to changes in sales increased for the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 1.3% due to higher customer usage offset by a decline in the number of customers. Weather-adjusted KWH sales to commercial customers decreased 0.1% due to lower customer usage offset by customer growth. KWH sales to industrial customers increased 0.6% primarily due to an unplanned outage by a large customer in 2016.
Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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.
Wholesale Revenues – Affiliates
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(4) | | (44.4) |
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 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 the first quarter 2017, wholesale revenues from sales to affiliates were $5 million compared to $9 million for the corresponding period in 2016. The decrease was due to a $5 million decrease in KWH sales primarily due to the availability of lower cost alternatives offset by a $1 million increase associated with higher natural gas prices.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | |
| | First Quarter 2017
vs.
First Quarter 2016 |
| | (change in millions) | | (% change) |
| Fuel | $ | 2 |
| | 2.6 |
| Purchased power – non-affiliates | 1 |
| | N/M |
| Purchased power – affiliates | 2 |
| | 40.0 |
| Total fuel and purchased power expenses | $ | 5 |
| | |
N/M - Not meaningful
In the first quarter 2017, total fuel and purchased power expenses were $86 million compared to $81 million for the corresponding period in 2016. The increase was due to a $15 million increase in natural gas prices offset by a $10 million net decrease in the volume of KWHs generated and 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 Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | |
| | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 3,161 | | 3,588 |
Total purchased power (in millions of KWHs) | 242 | | 261 |
Sources of generation (percent) – | | | |
| Coal | 9 | | 11 |
| Gas | 91 | | 89 |
Cost of fuel, generated (in cents per net KWH) – | | | |
| Coal | 3.33 | | 3.55 |
| Gas | 2.65 | | 2.15 |
Average cost of fuel, generated (in cents per net KWH) | 2.71 | | 2.32 |
Average cost of purchased power (in cents per net KWH) | 3.33 | | 2.17 |
Fuel
In the first quarter 2017, total fuel expense was $78 million compared to $76 million for the corresponding period in 2016. The increase was due to a 17% increase in the average cost of fuel per KWH generated primarily due to a 23% higher cost of natural gas offset by a 12% decrease in the volume of KWHs generated primarily as a result of lower sales.
Purchased Power - Affiliates
In the first quarter 2017, purchased power expense from affiliates was $7 million compared to $5 million for the corresponding period in 2016. The increase was primarily due to a 35% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost, partially offset by a 6% decrease in the average cost per KWH purchased primarily as a result of lower fuel prices.
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 purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $5 | | 7.2 |
In the first quarter 2017, other operations and maintenance expenses were $74 million compared to $69 million for the corresponding period in 2016. The increase was primarily due to a $3 million increase in amortization of prior operations and maintenance expense deferrals associated with the Kemper IGCC in-service assets and a $2 million increase in generation maintenance expenses, including scheduled outages.
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.
Estimated Loss on Kemper IGCC
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $55 | | N/M |
N/M - Not meaningful
In the first quarters of 2017 and 2016, estimated probable losses on the Kemper IGCC of $108 million and $53 million, respectively, were recorded at Mississippi Power. These losses reflect 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 the Initial DOE Grants and excluding the Cost Cap Exceptions.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
GEORGIA POWER COMPANY
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Retail revenues | $ | 2,540 |
| | $ | 2,537 |
| | $ | 6,164 |
| | $ | 6,223 |
| $ | 1,689 |
| | $ | 1,717 |
|
| Wholesale revenues, non-affiliates | 49 |
| | 55 |
| | 131 |
| | 173 |
| 39 |
| | 41 |
|
| Wholesale revenues, affiliates | 9 |
| | 5 |
| | 24 |
| | 18 |
| 8 |
| | 5 |
|
| Other revenues | 100 |
| | 94 |
| | 302 |
| | 271 |
| 96 |
| | 109 |
|
| Total operating revenues | 2,698 |
| | 2,691 |
| | 6,621 |
| | 6,685 |
| 1,832 |
| | 1,872 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 575 |
| | 706 |
| | 1,390 |
| | 1,735 |
| 371 |
| | 376 |
|
| Purchased power, non-affiliates | 102 |
| | 90 |
| | 277 |
| | 227 |
| 88 |
| | 83 |
|
| Purchased power, affiliates | 142 |
| | 148 |
| | 392 |
| | 411 |
| 172 |
| | 139 |
|
| Other operations and maintenance | 496 |
| | 462 |
| | 1,393 |
| | 1,405 |
| 381 |
| | 457 |
|
| Depreciation and amortization | 215 |
| | 214 |
| | 639 |
| | 633 |
| 221 |
| | 211 |
|
| Taxes other than income taxes | 114 |
| | 107 |
| | 311 |
| | 302 |
| 98 |
| | 97 |
|
| Total operating expenses | 1,644 |
| | 1,727 |
| | 4,402 |
| | 4,713 |
| 1,331 |
| | 1,363 |
|
| Operating Income | 1,054 |
| | 964 |
| | 2,219 |
| | 1,972 |
| 501 |
| | 509 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (98 | ) | | (90 | ) | | (290 | ) | | (272 | ) | (101 | ) | | (94 | ) |
| Other income (expense), net | 11 |
| | 18 |
| | 35 |
| | 34 |
| 20 |
| | 17 |
|
| Total other income and (expense) | (87 | ) | | (72 | ) | | (255 | ) | | (238 | ) | (81 | ) | | (77 | ) |
| Earnings Before Income Taxes | 967 |
| | 892 |
| | 1,964 |
| | 1,734 |
| 420 |
| | 432 |
|
| Income taxes | 365 |
| | 337 |
| | 737 |
| | 657 |
| 156 |
| | 159 |
|
| Net Income | 602 |
| | 555 |
| | 1,227 |
| | 1,077 |
| 264 |
| | 273 |
|
| Dividends on Preferred and Preference Stock | 4 |
| | 4 |
| | 13 |
| | 13 |
| 4 |
| | 4 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 598 |
| | $ | 551 |
| | $ | 1,214 |
| | $ | 1,064 |
| $ | 260 |
| | $ | 269 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Net Income | $ | 602 |
| | $ | 555 |
| | $ | 1,227 |
| | $ | 1,077 |
| $ | 264 |
| | $ | 273 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
| Changes in fair value, net of tax of $-, $(7), $-, and $(7), respectively | — |
| | (11 | ) | | — |
| | (10 | ) | |
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 2 |
| | 2 |
| |
| Changes in fair value, net of tax of $- and $-, respectively | | — |
| | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively | | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | (10 | ) | | 2 |
| | (8 | ) | 1 |
| | 1 |
|
| Comprehensive Income | $ | 603 |
| | $ | 545 |
| | $ | 1,229 |
| | $ | 1,069 |
| $ | 265 |
| | $ | 274 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 1,227 |
| | $ | 1,077 |
| $ | 264 |
| | $ | 273 |
|
| Adjustments to reconcile net income to net cash provided from operating activities -- | | | | |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 794 |
| | 766 |
| 271 |
| | 261 |
|
| Deferred income taxes | 346 |
| | 12 |
| 71 |
| | 55 |
|
| Allowance for equity funds used during construction | (36 | ) | | (24 | ) | (13 | ) | | (14 | ) |
| Deferred expenses | (40 | ) | | (45 | ) | 38 |
| | 38 |
|
| Pension, postretirement, and other employee benefits | (14 | ) | | 40 |
| (21 | ) | | (10 | ) |
| Settlement of asset retirement obligations | (93 | ) | | (18 | ) | (22 | ) | | (24 | ) |
| Other, net | 4 |
| | 48 |
| (29 | ) | | 27 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (162 | ) | | 37 |
| 142 |
| | 155 |
|
| -Fossil fuel stock | 128 |
| | 141 |
| (38 | ) | | 36 |
|
| -Prepaid income taxes | 45 |
| | 244 |
| 5 |
| | 38 |
|
| -Other current assets | 17 |
| | (17 | ) | (16 | ) | | 12 |
|
| -Accounts payable | 39 |
| | (118 | ) | (155 | ) | | 4 |
|
| -Accrued taxes | (22 | ) | | 54 |
| (235 | ) | | (235 | ) |
| -Accrued compensation | (26 | ) | | (34 | ) | (87 | ) | | (66 | ) |
| -Retail fuel cost over recovery | | (66 | ) | | 14 |
|
| -Other current liabilities | 53 |
| | (3 | ) | 2 |
| | 2 |
|
| Net cash provided from operating activities | 2,260 |
| | 2,160 |
| 111 |
| | 566 |
|
| Investing Activities: | | | | | | |
| Property additions | (1,566 | ) | | (1,321 | ) | (556 | ) | | (553 | ) |
| Nuclear decommissioning trust fund purchases | (563 | ) | | (815 | ) | (161 | ) | | (211 | ) |
| Nuclear decommissioning trust fund sales | 558 |
| | 810 |
| 155 |
| | 206 |
|
| Cost of removal, net of salvage | (45 | ) | | (57 | ) | (17 | ) | | (15 | ) |
| Change in construction payables, net of joint owner portion | (139 | ) | | 44 |
| (36 | ) | | (101 | ) |
| Prepaid long-term service agreements | (27 | ) | | (60 | ) | |
| Payments pursuant to LTSAs | | (22 | ) | | (11 | ) |
| Sale of property | | 63 |
| | — |
|
| Other investing activities | 24 |
| | 11 |
| 8 |
| | (4 | ) |
| Net cash used for investing activities | (1,758 | ) | | (1,388 | ) | (566 | ) | | (689 | ) |
| Financing Activities: | | | | | | |
| Decrease in notes payable, net | (63 | ) | | (26 | ) | (391 | ) | | (158 | ) |
| Proceeds — | | | | | | |
| Capital contributions from parent company | 294 |
| | 41 |
| 345 |
| | 218 |
|
| Pollution control revenue bonds | — |
| | 274 |
| |
| Senior notes | 650 |
| | — |
| 850 |
| | 650 |
|
| FFB loan | 300 |
| | 600 |
| |
| Short-term borrowings | — |
| | 250 |
| |
| Redemptions and repurchases — | | | | | | |
| Pollution control revenue bonds | (4 | ) | | (268 | ) | — |
| | (4 | ) |
| Senior notes | (700 | ) | | (525 | ) | — |
| | (250 | ) |
| Short-term borrowings | — |
| | (250 | ) | |
| Payment of common stock dividends | (979 | ) | | (776 | ) | (320 | ) | | (326 | ) |
| Other financing activities | (20 | ) | | (31 | ) | (11 | ) | | (14 | ) |
| Net cash used for financing activities | (522 | ) | | (711 | ) | |
| Net cash provided from financing activities | | 473 |
| | 116 |
|
| Net Change in Cash and Cash Equivalents | (20 | ) | | 61 |
| 18 |
| | (7 | ) |
| Cash and Cash Equivalents at Beginning of Period | 67 |
| | 24 |
| 3 |
| | 67 |
|
| Cash and Cash Equivalents at End of Period | $ | 47 |
| | $ | 85 |
| $ | 21 |
| | $ | 60 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid during the period for — | | | | |
| Interest (net of $15 and $10 capitalized for 2016 and 2015, respectively) | $ | 277 |
| | $ | 251 |
| |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $5 and $5 capitalized for 2017 and 2016, respectively) | | $ | 88 |
| | $ | 86 |
|
| Income taxes, net | 188 |
| | 311 |
| (5 | ) | | (88 | ) |
| Noncash transactions — Accrued property additions at end of period | 226 |
| | 192 |
| 320 |
| | 290 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 47 |
| | $ | 67 |
| | $ | 21 |
| | $ | 3 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 718 |
| | 541 |
| | 470 |
| | 523 |
|
| Unbilled revenues | | 298 |
| | 188 |
| | 200 |
| | 224 |
|
| Joint owner accounts receivable | | 46 |
| | 227 |
| | 146 |
| | 57 |
|
| Income taxes receivable, current | | — |
| | 114 |
| |
| Other accounts and notes receivable | | 55 |
| | 57 |
| | 57 |
| | 81 |
|
| Affiliated | | 15 |
| | 18 |
| | 12 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) | | (3 | ) | | (3 | ) |
| Fossil fuel stock | | 274 |
| | 402 |
| | 336 |
| | 298 |
|
| Materials and supplies | | 470 |
| | 449 |
| | 474 |
| | 479 |
|
| Vacation pay | | 90 |
| | 91 |
| |
| Prepaid income taxes | | 111 |
| | 156 |
| |
| Prepaid expenses | | | 35 |
| | 105 |
|
| Other regulatory assets, current | | 115 |
| | 123 |
| | 195 |
| | 193 |
|
| Other current assets | | 89 |
| | 92 |
| | 38 |
| | 38 |
|
| Total current assets | | 2,326 |
| | 2,523 |
| | 1,981 |
| | 2,016 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 33,394 |
| | 31,841 |
| | 34,059 |
| | 33,841 |
|
| Less accumulated provision for depreciation | | 11,234 |
| | 10,903 |
| |
| Less: Accumulated provision for depreciation | | | 11,443 |
| | 11,317 |
|
| Plant in service, net of depreciation | | 22,160 |
| | 20,938 |
| | 22,616 |
| | 22,524 |
|
| Other utility plant, net | | — |
| | 171 |
| |
| Nuclear fuel, at amortized cost | | 556 |
| | 572 |
| | 570 |
| | 569 |
|
| Construction work in progress | | 4,888 |
| | 4,775 |
| | 5,183 |
| | 4,939 |
|
| Total property, plant, and equipment | | 27,604 |
| | 26,456 |
| | 28,369 |
| | 28,032 |
|
| Other Property and Investments: | | | | | | | | |
| Equity investments in unconsolidated subsidiaries | | 61 |
| | 64 |
| | 58 |
| | 60 |
|
| Nuclear decommissioning trusts, at fair value | | 835 |
| | 775 |
| | 853 |
| | 814 |
|
| Miscellaneous property and investments | | 42 |
| | 43 |
| | 46 |
| | 46 |
|
| Total other property and investments | | 938 |
| | 882 |
| | 957 |
| | 920 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 675 |
| | 679 |
| | 676 |
| | 676 |
|
| Other regulatory assets, deferred | | 2,530 |
| | 2,152 |
| | 2,792 |
| | 2,774 |
|
| Other deferred charges and assets | | 175 |
| | 173 |
| | 473 |
| | 417 |
|
| Total deferred charges and other assets | | 3,380 |
| | 3,004 |
| | 3,941 |
| | 3,867 |
|
| Total Assets | | $ | 34,248 |
| | $ | 32,865 |
| | $ | 35,248 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 458 |
| | $ | 712 |
| | $ | 488 |
| | $ | 460 |
|
| Notes payable | | 95 |
| | 158 |
| | — |
| | 391 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 451 |
| | 411 |
| | 347 |
| | 438 |
|
| Other | | 464 |
| | 750 |
| | 657 |
| | 589 |
|
| Customer deposits | | 265 |
| | 264 |
| | 268 |
| | 265 |
|
| Accrued taxes — | | | | | | | | |
| Accrued income taxes | | 14 |
| | 12 |
| | 56 |
| | 17 |
|
| Other accrued taxes | | 310 |
| | 325 |
| | 115 |
| | 390 |
|
| Accrued interest | | 110 |
| | 99 |
| | 115 |
| | 106 |
|
| Accrued vacation pay | | 62 |
| | 62 |
| |
| Accrued compensation | | 118 |
| | 142 |
| | 110 |
| | 224 |
|
| Asset retirement obligations, current | | 313 |
| | 179 |
| | 305 |
| | 299 |
|
| Over recovered regulatory clause revenues, current | | 125 |
| | 10 |
| |
| Other current liabilities | | 197 |
| | 171 |
| | 241 |
| | 297 |
|
| Total current liabilities | | 2,982 |
| | 3,295 |
| | 2,702 |
| | 3,476 |
|
| Long-term Debt | | 10,114 |
| | 9,616 |
| | 11,042 |
| | 10,225 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 5,969 |
| | 5,627 |
| | 6,073 |
| | 6,000 |
|
| Deferred credits related to income taxes | | 103 |
| | 105 |
| | 119 |
| | 121 |
|
| Accumulated deferred investment tax credits | | 199 |
| | 204 |
| | 253 |
| | 256 |
|
| Employee benefit obligations | | 906 |
| | 949 |
| | 673 |
| | 703 |
|
| Asset retirement obligations, deferred | | 2,241 |
| | 1,737 |
| | 2,256 |
| | 2,233 |
|
| Other deferred credits and liabilities | | 203 |
| | 347 |
| | 214 |
| | 199 |
|
| Total deferred credits and other liabilities | | 9,621 |
| | 8,969 |
| | 9,588 |
| | 9,512 |
|
| Total Liabilities | | 22,717 |
| | 21,880 |
| | 23,332 |
| | 23,213 |
|
| Preferred Stock | | 45 |
| | 45 |
| | 45 |
| | 45 |
|
| Preference Stock | | 221 |
| | 221 |
| | 221 |
| | 221 |
|
| 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 | | 6,585 |
| | 6,275 |
| | 7,238 |
| | 6,885 |
|
| Retained earnings | | 4,295 |
| | 4,061 |
| | 4,026 |
| | 4,086 |
|
| Accumulated other comprehensive loss | | (13 | ) | | (15 | ) | | (12 | ) | | (13 | ) |
| Total common stockholder's equity | | 11,265 |
| | 10,719 |
| | 11,650 |
| | 11,356 |
|
| Total Liabilities and Stockholder's Equity | | $ | 34,248 |
| | $ | 32,865 |
| | $ | 35,248 |
| | $ | 34,835 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Georgia Power 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 Georgia Power'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. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs.restoration following major storms. Georgia Power 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 Georgia Power for the foreseeable future.
On October 20, 2016,March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Also on March 29, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC Staff entered into a settlement agreement resolving certain prudence and cost recovery mattersthe other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. The settlement agreementContractor's bankruptcy filing is subjectexpected to approvalhave a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia PSC.Power's financial statements. The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
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 on April 14, 2016, Georgia Power's 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. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Georgia Power continues to focus on several key performance indicators. These indicators include,including, but are 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. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $47 | | 8.5 | | $150 | | 14.1 |
Georgia Power's net income after dividends on preferred and preference stock was $598 million for the third quarter 2016 compared to $551 million for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, and higher retail revenues due to warmer weather as compared to the corresponding period in 2015, partially offset by higher non-fuel operating expenses.
For year-to-date 2016, net income after dividends on preferred and preference stock was $1.21 billion compared to $1.06 billion for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, the 2015 correction of an error affecting billings to a small number of large commercial and industrial customers, higher retail revenues in the third quarter
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2016 dueRESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(9) | | (3.3) |
Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2017 was $260 million compared to warmer weather as compared to$269 million for the corresponding period in 2015, and lower non-fuel operating expenses. Partially offsetting the increase were lower retail revenues in the first quarter 20162016. The decrease was primarily due to milder weather as compared to the corresponding period in 2015.2016, partially offset by lower non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 0.1 | | $(59) | | (0.9) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(28) | | (1.6) |
Retail revenues increased slightly inIn the thirdfirst quarter 2016 compared to the corresponding period in 2015. For year-to-date 2016,2017, retail revenues were $6.16$1.69 billion compared to $6.22$1.72 billion for the corresponding period in 2015.2016.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | First Quarter 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) |
| Retail – prior year | $ | 2,537 |
| | | | $ | 6,223 |
| | | $ | 1,717 |
| | |
| Estimated change resulting from – | | | | | | | | | | |
| Rates and pricing | 22 |
| | 0.9 |
| | 167 |
| | 2.7 |
| 26 |
| | 1.5 |
|
| Sales growth | 1 |
| | — |
| | 3 |
| | — |
| |
| Sales decline | | (12 | ) | | (0.7 | ) |
| Weather | 105 |
| | 4.1 |
| | 75 |
| | 1.2 |
| (72 | ) | | (4.2 | ) |
| Fuel cost recovery | (125 | ) | | (4.9 | ) | | (304 | ) | | (4.9 | ) | 30 |
| | 1.8 |
|
| Retail – current year | $ | 2,540 |
| | 0.1 | % | | $ | 6,164 |
| | (1.0 | )% | $ | 1,689 |
| | (1.6 | )% |
Revenues associated with changes in rates and pricing increased in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 20152016 primarily due to increases in base tariffs approved under the 2013 ARPrate pricing effect of decreased customer usage and the NCCR tariff, all effective January 1, 2016. Also contributing to the increase for year-to-date 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of largehigher contributions from commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales were essentially flatdecreased in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 2015.2016. Weather-adjusted residential KWH sales increased 1.7%1.3%, weather-adjusted commercial KWH sales decreased 0.7%2.5%, and weather-adjusted industrial KWH sales decreased 3.4%3.2% in the thirdfirst quarter 20162017 when compared to the corresponding period in 2015. For year-to-date 2016, weather-adjusted residential KWH sales increased 1.0%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 0.5% when compared to the corresponding period in 2015.2016. An increase of approximately 29,000 residential customers since September 30, 2015March 31, 2016 contributed to the increase in weather-adjusted residential KWH sales, partially offset by a decline in average customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting.sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,0001,400 commercial customers since September 30, 2015.March 31, 2016. Decreased demand in the pipeline, textiles,chemicals, paper, transportation, and stone, clay, and glass sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the non-manufacturing sector.
Fuel revenueslumber and costs are allocated between retailrubber sectors. A strong dollar, low oil prices, weak global economic conditions, and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $125 million and $304 millioneconomic policy uncertainty have constrained sales in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to lower fuel prices. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuelindustrial sector.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(6) | | (10.9) | | $(42) | | (24.3) |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. 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 Georgia Power'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 have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost to produce the energy.
In the third quarter 2016, wholesale revenues from sales to non-affiliates were $49 million compared to $55 million for the corresponding period in 2015 related to a $7 million decrease in capacity revenues, partially offset by a $1 million increase in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $131 million compared to $173 million for the corresponding period in 2015 related to a $28 million decrease in capacity revenues and a $14 million decrease in energy revenues. The decreases in capacity revenues reflect the expiration of wholesale contracts in the second quarter 2016. In addition, the decrease in capacity revenues for year-to-date 2016 reflects the retirement of 14 coal-fired generating units since March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decrease in energy revenues for year-to-date 2016 was primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information related to Georgia Power's environmental compliance strategy.
Other Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 6.4 | | $31 | | 11.4 |
For year-to-date 2016, other revenues were $302 million compared to $271 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to customer temporary facilities services revenues, a $9 million increase in outdoor lighting revenues, and a $3 million increase in solar application fee revenues. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information on Georgia Power's solar renewable energy program.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $30 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to higher natural gas prices and less available hydro generation, partially offset by lower energy sales resulting from milder weather in the first quarter 2017 as compared to the corresponding period in 2016. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" in Item 7 of the Form 10-K for additional information.
Other Revenues
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(13) | | (11.9) |
In the first quarter 2017, other revenues were $96 million compared to $109 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment for customer temporary facilities services revenues in 2016, partially offset by a $4 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | First Quarter 2017
vs.
First Quarter 2016 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) |
| Fuel | | $ | (131 | ) | | (18.6 | ) | | $ | (345 | ) | | (19.9 | ) | $ | (5 | ) | | (1.3 | ) |
| Purchased power – non-affiliates | | 12 |
| | 13.3 |
| | 50 |
| | 22.0 |
| 5 |
| | 6.0 |
|
| Purchased power – affiliates | | (6 | ) | | (4.1 | ) | | (19 | ) | | (4.6 | ) | 33 |
| | 23.7 |
|
| Total fuel and purchased power expenses | | $ | (125 | ) | | | | $ | (314 | ) | | | $ | 33 |
| | |
In the thirdfirst quarter 2016,2017, total fuel and purchased power expenses were $819$631 million compared to $944$598 million in the corresponding period in 2015.2016. The decreaseincrease in the thirdfirst quarter 20162017 was primarily due to a net decrease of $189$45 million increase in the average cost of fuel and purchased power primarily related to lower coalhigher natural gas prices and less rainfall for hydro generation, partially offset by a $64net decrease of $12 million increase related to the volume of KWHs generated and purchased as a result of warmerdue to milder weather as compared to the corresponding period in 20152016 resulting in higherlower customer demand.
For year-to-date 2016, total fuel and purchased power expenses were $2.06 billion compared to $2.37 billion in the corresponding period in 2015. The decrease in year-to-date 2016 was primarily due to a decrease of $326 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and a $20 million decrease related to the volume of KWHs generated, partially offset by a $32 million increase related to the volume of KWHs purchased primarily as a result of warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 resulting in higher customer demand.
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 Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail"Retail Regulatory Matters – Fuel Cost Recovery" hereinRecovery" in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Georgia Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | First Quarter 2017 | | First Quarter 2016 |
Total generation (in billions of KWHs) | 20 | | 19 | | 53 | | 53 | 14 | | 16 |
Total purchased power (in billions of KWHs) | 7 | | 7 | | 19 | | 18 | 7 | | 6 |
Sources of generation (percent) — | | |
| Coal | 44 | | 41 | | 37 | | 38 | 27 | | 30 |
| Nuclear | 22 | | 22 | | 23 | | 23 | 26 | | 23 |
| Gas | 34 | | 36 | | 38 | | 37 | 45 | | 42 |
| Hydro | — | | 1 | | 2 | | 2 | 2 | | 5 |
Cost of fuel, generated (in cents per net KWH) — | | |
| Coal | 3.16 | | 5.42 | | 3.32 | | 4.65 | 3.26 | | 3.56 |
| Nuclear | 0.85 | | 0.86 | | 0.85 | | 0.76 | 0.85 | | 0.86 |
| Gas | 2.61 | | 2.57 | | 2.27 | | 2.62 | 2.77 | | 2.01 |
Average cost of fuel, generated (in cents per net KWH) | 2.47 | | 3.37 | | 2.34 | | 2.98 | 2.39 | | 2.22 |
Average cost of purchased power (in cents per net KWH)(*) | 4.57 | | 4.54 | | 4.46 | | 4.50 | 4.47 | | 4.32 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the thirdfirst quarter 2016,2017, fuel expense was $575$371 million compared to $706$376 million in the corresponding period in 2015.2016. The decrease was primarily due to a 26.7% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices, partially offset by a 6.6% increase in the volume of KWHs generated due to warmer weather as compared to the corresponding period in 2015.
For year-to-date 2016, fuel expense was $1.39 billion compared to $1.74 billion in the corresponding period in 2015. The decrease was primarily due to a 21.5% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 3.0%21.1% decrease in the volume of KWHs generated by coal.coal, partially offset by a 37.8% increase in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the thirdfirst quarter 2016,2017, purchased power expense from non-affiliates was $102$88 million compared to $90$83 million in the corresponding period in 2015.2016. The increase was primarily due to an 18.3% increase in the volume of KWHs purchased due to warmer weather as compared to the corresponding period in 2015, partially offset by a 5.6% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
For year-to-date 2016, purchased power expense from non-affiliates was $277 million compared to $227 million in the corresponding period in 2015. The increase was primarily due to a 29.8% increase in the volume of KWHs purchased, partially offset by a 10.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
not material. 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
In the thirdfirst quarter 2016,2017, purchased power expense from affiliates was $142$172 million compared to $148$139 million in the corresponding period in 2015.2016. The decreaseincrease was primarily the result of a 2.4% decrease13.8% increase in the volume of KWHs purchased as Georgia Power's units generally dispatched atto meet customer demand and a lower cost than other available Southern Company system resources, partially offset by a 1.8%6.8% increase in the average cost per KWH purchased.
For year-to-date 2016, purchased power expenseprimarily resulting from affiliates was $392 million compared to $411 million in the corresponding period in 2015. The decrease was primarily the result of a 2.7% decrease in the volume of KWHs purchased due to the lower market cost of available energy as compared to Southern Company system resources.higher natural gas prices.
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 purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $34 | | 7.4 | | $(12) | | (0.9) |
In the third quarter 2016, other operations and maintenance expenses were $496 million compared to $462 million in the corresponding period in 2015. The increase was primarily due to a $26 million charge in connection with an employee attrition plan associated with cost containment activities, an $11 million increase in scheduled generation outage and maintenance costs, and an $11 million increase in transmission and distribution overhead line maintenance, partially offset by a $9 million decrease in pension costs.
For year-to-date 2016, other operations and maintenance expenses were $1.39 billion compared to $1.41 billion in the corresponding period in 2015. The decrease was primarily due to decreases of $31 million in scheduled generation outage and maintenance costs and $28 million in pension costs, partially offset by a $26 million charge
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(76) | | (16.6) |
In the first quarter 2017, other operations and maintenance expenses were $381 million compared to $457 million in connection with an employee attrition plan associated withthe corresponding period in 2016. The decrease is primarily due to cost containment activities animplemented in the third quarter 2016, a $19 million increase in gains from sales of $16integrated transmission system assets, and a $6 million decrease in demand-side management costs related to the timing of new programs. Cost containment activities contributed to decreases of $18 million in employee compensation and benefit costs, $14 million in generation maintenance costs, and $7 million in transmission and distribution overhead line maintenance, and an increase of $9 million for integrated transmission system billings.
See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note (F) to the Condensed Financial Statements herein for additional information related to the employee attrition plan and pension costs, respectively.maintenance.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 0.5 | | $6 | | 0.9 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $10 | | 4.7 |
For year-to-date 2016,In the first quarter 2017, depreciation and amortization was $639$221 million compared to $633$211 million in the corresponding period in 2015.2016. The increase was primarily due to a $25 million increase related to additional plant in service and a $9 million increase in other cost of removal, partially offset by a decrease of $14 million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $13 million related to unit retirements.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 6.5 | | $9 | | 3.0 |
In the third quarter 2016, taxes other than income taxes were $114 million compared to $107 million in the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $311 million compared to $302 million in the corresponding period in 2015. The increases were primarily due to increases in property taxes of $5 million and $8 million in the third quarter and year-to-date 2016, respectively, as a result of an increase in the assessed value of property.service.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $8 | | 8.9 | | $18 | | 6.6 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 7.4 |
In the thirdfirst quarter 2016,2017, interest expense, net of amounts capitalized was $98$101 million compared to $90$94 million in the corresponding period in 2015.2016. The increase was primarily due to a $7$6 million increase in interest due to senior note issuances and additional long-term borrowings from the FFB and higher interest ratesFFB.
See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on obligations for pollution control revenue bonds remarketed in 2015.
For year-to-date 2016, interest expense, net of amounts capitalized was $290 million compared to $272 million in the corresponding period in 2015. The increase was primarily due to a $27 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an increase of $5 million in AFUDC debt and a decrease of $4 million in interest due to lower interest rates on obligations for senior notes.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $28 | | 8.3 | | $80 | | 12.2 |
In the third quarter 2016, income taxes were $365 million compared to $337 million in the corresponding period in 2015. For year-to-date 2016, income taxes were $737 million compared to $657 million in the corresponding period in 2015. The increases were primarily due to higher pre-tax earnings.FFB.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity.providing electric service. These factors include Georgia Power'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 completionnext several years. The impact of the Contractor's bankruptcy on the construction cost and subsequent operationschedule of, ongoing construction projects, primarilyas well as the cost recovery for, Plant Vogtle Units 3 and 4.4 is also a major factor. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, 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. 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 Georgia Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.10-K and RISK FACTORS in Item 1A herein.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power'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. 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. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS),revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its supplemental finding regarding considerationplanned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.
The ultimate outcome of coststhese matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in supportItem 7 of the MATS rule. This finding does not impact MATS ruleForm 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
compliance requirements, costs, or deadlines, and all Georgia Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.
On September 6, 2016, the EPA designated all remaining areas within Georgia Power's service territory as attainment for the 2012 annual fine particulate matter NAAQS.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and certain other states. The State of Georgia's emission budget was not affected by the revisions but interstate emissions trading is restricted unless the state decides to voluntarily adopt a reduced budget. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on Georgia Power's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's asset retirement obligations (ARO) as of September 30, 2016.
Retail Regulatory Matters
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 tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing 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 "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein for additional information regarding fuel cost recovery.
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 on April 14, 2016, Georgia Power's 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 (collectively, Utilities) 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 utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Georgia PowerFuel Cost Recovery" in Item 7 of the Form 10-K for additional information regarding renewable energy projects.
As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.
On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.fuel cost recovery.
Integrated Resource Plan
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision 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 will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative 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.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of cost recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for information regarding fuel cost recovery.
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will
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reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's 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 Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
Vogtle 3 and 4 Agreement and Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to a cap.an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of certaina credit rating downgradesdowngrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 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 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4
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Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual 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 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) 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 accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent.
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 litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent forAmong other things, 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) reviserevised 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(ii) provided that delay liquidated damages will commence fromif the current estimated nuclear fuel loading date for each unit which isdoes not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; 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 $256 million had been paid as of September 30, 2016. 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 Westinghouse's acquisition of WECTEC: (i) Westinghouse 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. 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.
The Georgia PSC has approved fourteen VCM reports covering the periods through December 31, 2015, including construction capital costs incurred, which through that date totaled $3.3 billion. On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement
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Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia PSCPower, based on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.
Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for its review.convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia PSC's subsequent order,Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 5, 2016,28, 2017. On April 28, 2017, Georgia Power, filed supplemental information in supportacting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor Settlementfor subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the
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Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's position that all construction costsproportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to date have been prudently incurredthe Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and thatenforcement of the current estimatedToshiba Guarantee.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service capital costdates of December 2019 and schedule are reasonable.
On October 20, 2016,September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC Staff entered intoand the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
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 by including the related CWIP accounts in rate base during the construction period.
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On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation,when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016,that date totaled $3.7 billion. Georgia Power filed the fifteenthits sixteenth VCM report, with the Georgia PSC covering the period from JanuaryJuly 1 through June 30,December 31, 2016, requesting approval of $141$222 million of construction capital costs incurred during that period.period, with the Georgia PSC on February 27, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.8approximately $4.1 billion as of September 30, 2016. EstimatedMarch 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs during the construction period total approximately $2.4 billion,through March 31, 2017.
The ultimate outcome of which $1.2 billion had been incurred through September 30, 2016.these matters cannot be determined at this time.
On November 1, 2016,Other Matters
As of March 31, 2017, Georgia Power submitted its 2017 NCCR tariff filing requestinghad borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the current NCCR tariff rate remain effective for 2017 if theapplicable unit be placed in service prior to 2021. The net present value of Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase ofPower's PTCs is estimated at approximately $70 million.
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$400 million per unit.
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. Processes are in place
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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 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 labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressureGeorgia Power's previously estimated owner's costs of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2$10 million per month netand financing costs of delay liquidated damages and certain incentive payments that would no longer be required to be paidapproximately $30 million per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each ofmonth for 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 behalfare being evaluated as part of the Vogtle Owners) could arise throughout construction. These claims maycomprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.
The ultimate outcome of these matters cannot 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.determined at this time.
See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
The ultimate outcome of these matters cannot be determined at this time. See additional risks in Item 1A herein regarding the Contractor's bankruptcy.
Other Matters
Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power'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 by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGeorgia Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGeorgia PowerinItem8ofthe Form 10-K,Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion
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of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
Georgia Power regularly evaluates its operations and costs. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and on-going efforts to increase overall operating efficiencies, Georgia Power initiated cost containment activities throughout the enterprise in July 2016, including the announced closure of 104 local offices and an employee attrition plan affecting approximately 300 positions. Charges associated with the cost containment activities are not expected to have a material impact on Georgia Power's results of operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Georgia Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Georgia Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Georgia Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Georgia Power has not elected its transition method.
On February 25, 2016,March 10, 2017, the FASB issued ASU No. 2016-02,2017-07, Leases(Topic 842)Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2016-02)2017-07). ASU 2016-022017-07 requires lesseesthat 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 recognize onbe separately presented in the balance sheet a lease liability and a right-of-use assetincome statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all leases.cost components remain eligible for capitalization under FERC regulations. ASU 2016-02 also changes2017-07 will be applied retrospectively for the recognition, measurement, and presentation of expense associated with leasesthe service cost component and provides clarification regarding the identification of certainother components of contracts that would representnet periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a lease. The accounting required by lessors is relatively unchanged.prospective basis. ASU 2016-022017-07 is effective for fiscal yearsannual periods beginning after December 15, 2018, with early adoption permitted.2017, including interim periods within those annual periods. Georgia Power is currently evaluating the new standardstandard. The presentation changes required for net periodic pension and has not yet determined its ultimate impact; however,postretirement benefit costs will result in a decrease in Georgia Power'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 adoption of ASU 2016-02 is expected to have a significant impact on Georgia Power's balance sheet.
On March 30, 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. Most significantly, 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. Georgia Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Georgia Power intends to adopt the ASU in the fourth quarter 2016. The adoption2017-07 is not expected to have a material impact on the results of operations,Georgia Power's financial position, or cash flows of Georgia Power.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 2016.March 31, 2017. Georgia Power 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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.26 billion$111 million for the first ninethree months of 20162017 compared to $2.16 billion$566 million for the corresponding period in 2015.2016. The increasedecrease was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $1.76 billion$566 million for the first ninethree months of 20162017 compared to $1.39 billion$689 million for the corresponding period in 20152016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash used forprovided from financing activities totaled $522$473 million for the first ninethree months of 20162017 compared to $711$116 million in the corresponding period in 2015.2016. The decreaseincrease in cash used forprovided from financing activities is primarily due to higher issuances of senior notes, higher capital contributions received from Southern Company, and a maturity of senior note issuances,notes in 2016, partially offset by higher common stock dividends and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4.a reduction in short-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include an increase in long-term debt of $845 million due to issuances of senior notes, a decrease in notes payable of $391 million primarily due to changes in short-term liquidity needs, an increase in paid-in capital of $353 million primarily due to capital contributions received from Southern Company, and an increase in property, plant, and equipment of $1.1 billion$337 million to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $638 million and other regulatory assets, deferred of $378 million primarily related to changes in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information regarding changes in ash pond closure strategy.facilities.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $458$488 million will be required through September 30, 2017March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
Georgia Power's construction program is currently estimated to total $2.6 billion Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for 2017, $2.7 billion for 2018, $2.3 billion for 2019, $2.2 billion for 2020, and $1.8 billion for 2021. These amounts include expenditures of approximately $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction ofadditional information regarding Plant Vogtle Units 3 and 4. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
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 statutes 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 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. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Except as described below with respect to the DOE loan guarantees, Georgia Power 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, short-term debt, external security issuances, term loans, and equity contributions from Southern Company.Company, and, to the extent available, borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, Georgia Power may make borrowings throughhas entered into a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power andwith the DOE, under which the proceeds of whichborrowings 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. Eligible Project Costs incurred through September 30, 2016March 31, 2017 would allow for borrowings of up to $2.6$2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5$2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of September 30, 2016,At March 31, 2017, Georgia Power's current liabilities exceeded current assets by $656 million primarily due to$721 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt.debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, as well as FFB borrowings, commercial paper, lines of credit, bank notes, andshort-term debt, external securitiessecurity issuances, as market conditions permit, andterm loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At September 30, 2016,March 31, 2017, Georgia Power had approximately $47$21 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 30, 2016March 31, 2017 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.
This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Georgia Power 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, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016March 31, 2017 was approximately $868 million. In addition, at September 30, 2016,March 31, 2017, Georgia Power had $250 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Georgia Power 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 Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each 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 September 30, 2016 | | 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) |
| Commercial paper | | $ | 95 |
| | 0.8 | % | | $ | 59 |
| | 0.8 | % | | $ | 197 |
|
|
| | | | | | | | | | | |
| | | Short-term Debt During the Period (*) |
| | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 152 |
| | 1.0 | % | | $ | 415 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.March 31, 2017. No short-term debt was outstanding at March 31, 2017. |
Georgia Power 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.
Credit Rating Risk
At March 31, 2017, Georgia Power 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, and construction of new generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at September 30, 2016March 31, 2017 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 93 |
| $ | 87 |
|
| Below BBB- and/or Baa3 | $ | 1,222 |
| $ | 1,224 |
|
Included in these amounts are certain agreements that could require collateral in the event that oneGeorgia Power 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 Georgia Power to access capital markets and would be likely to impact the cost at which it does so.
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 Georgia Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.
Financing Activities
In January 2016, $4.085 million aggregate principal amount of Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and Power Company Project), First Series 1993 matured.
In March 2016,2017, Georgia Power issued $325$450 million aggregate principal amount of Series 2016A 3.25%2017A 2.00% Senior Notes due April 1, 2026March 30, 2020 and $325$400 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A2017B 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities.March 30, 2027. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
Subsequent to March 31, 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016,Power may reoffer these bonds to the public at a later date.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.
In April 2016, Georgia Power's $250 million aggregate principal amount of Series 2011B 3.00% Senior Notes matured.
In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
In August 2016, Georgia Power's $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes matured.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power 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.
GULF POWER COMPANY
GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 |
| 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Retail revenues | $ | 377 |
| | $ | 363 |
| | $ | 978 |
| | $ | 983 |
| $ | 279 |
| | $ | 283 |
|
| Wholesale revenues, non-affiliates | 17 |
| | 30 |
| | 48 |
| | 82 |
| 17 |
| | 16 |
|
| Wholesale revenues, affiliates | 23 |
| | 17 |
| | 59 |
| | 52 |
| 37 |
| | 21 |
|
| Other revenues | 19 |
| | 19 |
| | 51 |
| | 53 |
| 17 |
| | 15 |
|
| Total operating revenues | 436 |
| | 429 |
| | 1,136 |
| | 1,170 |
| 350 |
| | 335 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 141 |
| | 143 |
| | 342 |
| | 375 |
| 108 |
| | 94 |
|
| Purchased power, non-affiliates | 33 |
| | 26 |
| | 95 |
| | 76 |
| 32 |
| | 30 |
|
| Purchased power, affiliates | 3 |
| | 4 |
| | 9 |
| | 22 |
| 2 |
| | 2 |
|
| Other operations and maintenance | 86 |
| | 90 |
| | 239 |
| | 274 |
| 84 |
| | 77 |
|
| Depreciation and amortization | 49 |
| | 40 |
| | 129 |
| | 100 |
| 18 |
| | 38 |
|
| Taxes other than income taxes | 34 |
| | 35 |
| | 93 |
| | 91 |
| 27 |
| | 29 |
|
| Loss on Plant Scherer Unit 3 | | 33 |
| | — |
|
| Total operating expenses | 346 |
| | 338 |
| | 907 |
| | 938 |
| 304 |
| | 270 |
|
| Operating Income | 90 |
| | 91 |
| | 229 |
| | 232 |
| 46 |
| | 65 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (11 | ) | | (12 | ) | | (36 | ) | | (38 | ) | (12 | ) | | (13 | ) |
| Other income (expense), net | (2 | ) | | 2 |
| | (4 | ) | | 8 |
| — |
| | (1 | ) |
| Total other income and (expense) | (13 | ) | | (10 | ) | | (40 | ) | | (30 | ) | (12 | ) | | (14 | ) |
| Earnings Before Income Taxes | 77 |
| | 81 |
| | 189 |
| | 202 |
| 34 |
| | 51 |
|
| Income taxes | 30 |
| | 31 |
| | 74 |
| | 75 |
| 14 |
| | 20 |
|
| Net Income | 47 |
| | 50 |
| | 115 |
| | 127 |
| 20 |
| | 31 |
|
| Dividends on Preference Stock | 2 |
| | 2 |
| | 7 |
| | 7 |
| 2 |
| | 2 |
|
| Net Income After Dividends on Preference Stock | $ | 45 |
| | $ | 48 |
| | $ | 108 |
| | $ | 120 |
| $ | 18 |
| | $ | 29 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Net Income | $ | 47 |
| | $ | 50 |
| | $ | 115 |
| | $ | 127 |
| $ | 20 |
| | $ | 31 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
| Changes in fair value, net of tax of $-, $-, $(3), and $-, respectively | — |
| | — |
| | (4 | ) | | — |
| |
| Changes in fair value, net of tax of $- and $(2), respectively | | (1 | ) | | (3 | ) |
| Total other comprehensive income (loss) | — |
| | — |
| | (4 | ) | | — |
| (1 | ) | | (3 | ) |
| Comprehensive Income | $ | 47 |
| | $ | 50 |
| | $ | 111 |
| | $ | 127 |
| $ | 19 |
| | $ | 28 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 115 |
| | $ | 127 |
| $ | 20 |
| | $ | 31 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 134 |
| | 105 |
| 20 |
| | 40 |
|
| Deferred income taxes | 15 |
| | 58 |
| 5 |
| | 9 |
|
| Loss on Plant Scherer Unit 3 | | 33 |
| | — |
|
| Other, net | (4 | ) | | 5 |
| (2 | ) | | (1 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (9 | ) | | 18 |
| (1 | ) | | 35 |
|
| -Fossil fuel stock | 49 |
| | 18 |
| 12 |
| | 15 |
|
| -Other current assets | 3 |
| | 32 |
| 6 |
| | 2 |
|
| -Accrued taxes | 40 |
| | 46 |
| (4 | ) | | 13 |
|
| -Accrued compensation | | (23 | ) | | (18 | ) |
| -Over recovered regulatory clause revenues | | (18 | ) | | 1 |
|
| -Other current liabilities | 30 |
| | 2 |
| 2 |
| | 5 |
|
| Net cash provided from operating activities | 373 |
| | 411 |
| 50 |
| | 132 |
|
| Investing Activities: | | | | | | |
| Property additions | (106 | ) | | (189 | ) | (46 | ) | | (32 | ) |
| Cost of removal, net of salvage | (8 | ) | | (9 | ) | (2 | ) | | (2 | ) |
| Change in construction payables | (7 | ) | | (29 | ) | (7 | ) | | (6 | ) |
| Other investing activities | (6 | ) | | (6 | ) | (2 | ) | | (2 | ) |
| Net cash used for investing activities | (127 | ) | | (233 | ) | (57 | ) | | (42 | ) |
| Financing Activities: | | | | | | |
| Decrease in notes payable, net | (42 | ) | | (34 | ) | (168 | ) | | (85 | ) |
| Proceeds — | | | | | | |
| Common stock issued to parent | — |
| | 20 |
| 175 |
| | — |
|
| Pollution control revenue bonds | — |
| | 13 |
| |
| Redemptions and repurchases — | | | | |
| Pollution control revenue bonds | — |
| | (13 | ) | |
| Senior notes | (125 | ) | | (60 | ) | |
| Capital contributions from parent company | | 4 |
| | 1 |
|
| Payment of common stock dividends | (90 | ) | | (98 | ) | (31 | ) | | (30 | ) |
| Other financing activities | 6 |
| | (4 | ) | 3 |
| | (2 | ) |
| Net cash used for financing activities | (251 | ) | | (176 | ) | (17 | ) | | (116 | ) |
| Net Change in Cash and Cash Equivalents | (5 | ) | | 2 |
| (24 | ) | | (26 | ) |
| Cash and Cash Equivalents at Beginning of Period | 74 |
| | 39 |
| 56 |
| | 74 |
|
| Cash and Cash Equivalents at End of Period | $ | 69 |
| | $ | 41 |
| $ | 32 |
| | $ | 48 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $- and $5 capitalized for 2016 and 2015, respectively) | $ | 29 |
| | $ | 27 |
| |
| Interest (net of $- and $- capitalized for 2017 and 2016, respectively) | | $ | 2 |
| | $ | 3 |
|
| Income taxes, net | 14 |
| | (37 | ) | — |
| | (25 | ) |
| Noncash transactions — Accrued property additions at end of period | 13 |
| | 17 |
| 26 |
| | 15 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 69 |
| | $ | 74 |
| | $ | 32 |
| | $ | 56 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 94 |
| | 76 |
| | 58 |
| | 72 |
|
| Unbilled revenues | | 74 |
| | 54 |
| | 52 |
| | 55 |
|
| Under recovered regulatory clause revenues | | 2 |
| | 20 |
| | 47 |
| | 17 |
|
| Income taxes receivable, current | | — |
| | 27 |
| |
| Other accounts and notes receivable | | 4 |
| | 9 |
| | 9 |
| | 6 |
|
| Affiliated | | 3 |
| | 1 |
| | 28 |
| | 17 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) | | (1 | ) | | (1 | ) |
| Fossil fuel stock | | 59 |
| | 108 |
| | 59 |
| | 71 |
|
| Materials and supplies | | 56 |
| | 56 |
| | 56 |
| | 55 |
|
| Other regulatory assets, current | | 62 |
| | 90 |
| | 50 |
| | 44 |
|
| Other current assets | | 15 |
| | 22 |
| | 22 |
| | 30 |
|
| Total current assets | | 437 |
| | 536 |
| | 412 |
| | 422 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 5,073 |
| | 5,045 |
| | 5,110 |
| | 5,140 |
|
| Less accumulated provision for depreciation | | 1,387 |
| | 1,296 |
| |
| Less: Accumulated provision for depreciation | | | 1,401 |
| | 1,382 |
|
| Plant in service, net of depreciation | | 3,686 |
| | 3,749 |
| | 3,709 |
| | 3,758 |
|
| Other utility plant, net | | — |
| | 62 |
| |
| Construction work in progress | | 64 |
| | 48 |
| | 67 |
| | 51 |
|
| Total property, plant, and equipment | | 3,750 |
| | 3,859 |
| | 3,776 |
| | 3,809 |
|
| Other Property and Investments | | 4 |
| | 4 |
| |
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 59 |
| | 61 |
| | 57 |
| | 58 |
|
| Other regulatory assets, deferred | | 507 |
| | 427 |
| | 501 |
| | 512 |
|
| Other deferred charges and assets | | 45 |
| | 33 |
| | 21 |
| | 21 |
|
| Total deferred charges and other assets | | 611 |
| | 521 |
| | 579 |
| | 591 |
|
| Total Assets | | $ | 4,802 |
| | $ | 4,920 |
| | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 195 |
| | $ | 110 |
| | $ | 92 |
| | $ | 87 |
|
| Notes payable | | 100 |
| | 142 |
| | 100 |
| | 268 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 50 |
| | 55 |
| | 47 |
| | 59 |
|
| Other | | 41 |
| | 44 |
| | 47 |
| | 54 |
|
| Customer deposits | | 35 |
| | 36 |
| | 35 |
| | 35 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 19 |
| | 4 |
| |
| Other accrued taxes | | 34 |
| | 9 |
| |
| Accrued taxes | | | 16 |
| | 20 |
|
| Accrued interest | | 19 |
| | 9 |
| | 18 |
| | 8 |
|
| Accrued compensation | | 20 |
| | 25 |
| | 17 |
| | 40 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
| | 22 |
| | 22 |
|
| Asset retirement obligations, current | | | 32 |
| | 16 |
|
| Other regulatory liabilities, current | | 28 |
| | 22 |
| | 5 |
| | 16 |
|
| Liabilities from risk management activities | | 30 |
| | 49 |
| |
| Other current liabilities | | 41 |
| | 40 |
| | 30 |
| | 24 |
|
| Total current liabilities | | 634 |
| | 567 |
| | 461 |
| | 649 |
|
| Long-term Debt | | 989 |
| | 1,193 |
| | 987 |
| | 987 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 904 |
| | 893 |
| | 952 |
| | 948 |
|
| Employee benefit obligations | | 125 |
| | 129 |
| | 94 |
| | 96 |
|
| Deferred capacity expense | | 125 |
| | 141 |
| | 114 |
| | 119 |
|
| Asset retirement obligations | | 119 |
| | 113 |
| | 106 |
| | 120 |
|
| Accrued environmental remediation | | 41 |
| | 42 |
| |
| Other cost of removal obligations | | 248 |
| | 233 |
| | 226 |
| | 249 |
|
| Other regulatory liabilities, deferred | | 48 |
| | 47 |
| | 48 |
| | 47 |
|
| Other deferred credits and liabilities | | 41 |
| | 60 |
| | 78 |
| | 71 |
|
| Total deferred credits and other liabilities | | 1,651 |
| | 1,658 |
| | 1,618 |
| | 1,650 |
|
| Total Liabilities | | 3,274 |
| | 3,418 |
| | 3,066 |
| | 3,286 |
|
| Preference Stock | | 147 |
| | 147 |
| | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | | | | | |
| Common stock, without par value — | | | | | | | | |
| Authorized — 20,000,000 shares | | | | | | | | |
| Outstanding — 5,642,717 shares | | 503 |
| | 503 |
| |
| Outstanding — March 31, 2017: 7,392,717 shares | | | | | |
| — December 31, 2016: 5,642,717 shares | | | 678 |
| | 503 |
|
| Paid-in capital | | 579 |
| | 567 |
| | 594 |
| | 589 |
|
| Retained earnings | | 303 |
| | 285 |
| | 282 |
| | 296 |
|
| Accumulated other comprehensive loss | | (4 | ) | | — |
| |
| Accumulated other comprehensive income | | | — |
| | 1 |
|
| Total common stockholder's equity | | 1,381 |
| | 1,355 |
| | 1,554 |
| | 1,389 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,802 |
| | $ | 4,920 |
| | $ | 4,767 |
| | $ | 4,822 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricityelectric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Gulf Power'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, restoration following major storms, fuel, and fuel.capital expenditures. Gulf Power 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 Gulf Power for the foreseeable future.
Through 2015, long-term non-affiliateOn April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity sales fromcost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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) provided, which was recorded in the majorityfirst quarter 2017. The remaining issues related to the inclusion of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownershipinvestment in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 andhave been resolved as a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverabilityresult of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 20162017 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.
On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors includeSettlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolvedunit through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earningsenvironmental cost recovery clause rate approved by the Florida PSC in future years until Gulf Power is able to find a suitable alternative related to this asset.November 2016.
Gulf Power continues to focus on several key performance indicators. These indicators includeincluding, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For
RESULTS OF OPERATIONS
Net Income
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(11) | | (37.9) |
Gulf Power's net income after dividends on preference stock for the first quarter 2017 was $18 million compared to $29 million for the corresponding period in 2016. The decrease was primarily due to a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement, partially offset by a decrease in depreciation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 ofregarding the Form 10-K.2017 Rate Case Settlement Agreement.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net IncomeRetail Revenues
| | | Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 | |
| First Quarter 2017 vs. First Quarter 2016 | | First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | (% change) |
$(3)(4) | | (6.3) | | $(12) | | (10.0) | | (1.4) |
Gulf Power's net income after dividends on preference stock forIn the thirdfirst quarter 2016 was $452017, retail revenues were $279 million compared to $48$283 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by an increase in retail revenues primarily due to warmer weather and lower operations and maintenance expenses.
Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $108 million compared to $120 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by lower operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $14 | | 3.9 | | $(5) | | (0.5) |
In the third quarter 2016, retail revenues were $377 million compared to $363 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $978 million compared to $983 million for the corresponding period in 2015.2016.
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | First Quarter 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) |
| Retail – prior year | $ | 363 |
| | | | $ | 983 |
| | | $ | 283 |
| | |
| Estimated change resulting from – | | | | | | | | | | |
| Rates and pricing | 11 |
| | 3.0 |
| | 28 |
| | 2.8 |
| 1 |
| | 0.4 |
|
| Sales growth (decline) | (1 | ) | | (0.3 | ) | | — |
| | — |
| |
| Sales decline | | (2 | ) | | (0.7 | ) |
| Weather | 5 |
| | 1.4 |
| | (3 | ) | | (0.3 | ) | (5 | ) | | (1.8 | ) |
| Fuel and other cost recovery | (1 | ) | | (0.3 | ) | | (30 | ) | | (3.1 | ) | 2 |
| | 0.7 |
|
| Retail – current year | $ | 377 |
| | 3.8 | % | | $ | 978 |
| | (0.6 | )% | $ | 279 |
| | (1.4 | )% |
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing increased in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 20152016 primarily due to an increase in the environmental cost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause rate, both effective in January 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Plant Scherer Unit 3 being rededicated to retail service.
Revenues attributable to changes in sales decreased slightly in the thirdfirst quarter 20162017 when compared to the corresponding period in 2015.2016. For the thirdfirst quarter 2016,2017, weather-adjusted KWH sales to residential and commercial customers decreased 1.9%1.5% and 0.5%0.7%, respectively, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers increased 1.3%decreased 8.8% for the thirdfirst quarter 20162017 primarily due to decreasedincreased customer co-generationco-generation.
Fuel and changesother cost recovery revenues increased in customers' operations.
Revenues attributable to changes in sales remained essentially flat year-to-date 2016the first quarter 2017 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 0.4% and 1.0%, respectively, due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers increased 2.9%2016, primarily due to decreased customer co-generation, partially offset by changes in customers' operations.
Fuel and other cost recovery revenues decreased in the third quarter 2016 when compared to the corresponding period in 2015, primarily due to lowerhigher recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higherlower recoverable costs under Gulf Power's energy conservationfuel cost recovery clause. Fuel and otherpurchased power capacity cost recovery revenues decreased year-to-date 2016 when compared to the corresponding period in 2015, primarily due to a decrease in fuel costs as a result of decreased generation and lower purchased power energy costs. Lower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher recoverable costs under Gulf Power's energy conservation cost recovery clause, also contributed to this decrease.clauses. 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. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(13) | | (43.3) | | $(34) | | (41.5) |
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 Gulf Power'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 Gulf Power'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.
In the third quarter 2016, wholesale revenues from sales to non-affiliates were $17 million compared to $30 million for the corresponding period in 2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $48 million compared to $82 million for the corresponding period in 2015. These decreases were primarily due to a 62.1% and 52.3% decrease in capacity revenues for the third quarter and year-to-date 2016, respectively, resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 35.3 | | $7 | | 13.5 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $16 | | 76.2 |
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 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 the thirdfirst quarter 2016,2017, wholesale revenues from sales to affiliates were $23$37 million compared to $17$21 million for the corresponding period in 2015.2016. The increase was primarily due to a 42.8% increase in KWH sales as a result of higher sales to the power pool due to greater Southern Company system load. For year-to-date 2016, wholesale revenues from sales to affiliates were $59 million compared to $52 million for the corresponding period in 2015. The increase was primarily due to a 33.7%55.4% increase in KWH sales resulting from lower planned unit outages for Gulf Power'sincreased generation resources.as a result of system reliability requirements.
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | First Quarter 2017
vs.
First Quarter 2016 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) |
| Fuel | | $ | (2 | ) | | (1.4 | ) | | $ | (33 | ) | | (8.8 | ) | $ | 14 |
| | 14.9 |
| Purchased power – non-affiliates | | 7 |
| | 26.9 |
| | 19 |
| | 25.0 |
| 2 |
| | 6.7 |
| Purchased power – affiliates | | (1 | ) | | (25.0 | ) | | (13 | ) | | (59.1 | ) | |
| Total fuel and purchased power expenses | | $ | 4 |
| | | | $ | (27 | ) | | | $ | 16 |
| |
In the thirdfirst quarter 2016,2017, total fuel and purchased power expenses were $177$142 million compared to $173$126 million for the corresponding period in 2015.2016. The increase was primarily due tothe result of a $7$10 million net increase related to the volume of KWHs generated and purchased as a result ofdue to higher customer loads ongeneration from Gulf Power's system, partially offset bycoal-fired units and a $3$6 million decrease in the average cost of fuel and purchased power.
For year-to-date 2016, total fuel and purchased power expenses were $446 million compared to $473 million for the corresponding period in 2015. The decrease was primarily the result of a $40 million decreasenet increase due to the lowerhigher average cost of fuel and purchased power partially offset by a $13 million net increase related to the volume of KWHs purchased fromfor Gulf Power's gas-fired PPA resource.
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 Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Gulf Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 2,775 | | 2,839 | | 6,654 | | 7,435 | 2,322 | | 1,816 |
Total purchased power (in millions of KWHs) | 1,906 | | 1,637 | | 5,295 | | 4,231 | 1,459 | | 1,760 |
Sources of generation (percent) – | | |
| Coal | 68 | | 64 | | 57 | | 61 | 53 | | 42 |
| Gas | 32 | | 36 | | 43 | | 39 | 47 | | 58 |
Cost of fuel, generated (in cents per net KWH) – | | |
| Coal | 3.55 | | 3.67 | | 3.80 | | 3.88 | 3.27 | | 3.92 |
| Gas | 4.38 | | 4.32 | | 4.06 | | 4.22 | 3.24 | | 3.75 |
Average cost of fuel, generated (in cents per net KWH) | 3.81 | | 3.90 | | 3.91 | | 4.01 | 3.26 | | 3.82 |
Average cost of purchased power (in cents per net KWH)(*) | 3.79 | | 3.83 | | 3.51 | | 4.12 | 4.57 | | 3.22 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the thirdfirst quarter 2016,2017, fuel expense was $141$108 million compared to $143$94 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to a 12.9% decrease in the volume of KWHs generated by Gulf Power's gas-fired generation resources due to higher planned maintenance and a 2.3% decrease in the average cost of fuel. The decreases were partially offset by a 3.6%60.9% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources.
For year-to-date 2016, fuel expense was $342 million compared to $375 million for the corresponding period in 2015. The decrease was primarily due to a 17.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to the lower cost of gas-fired resources andsystem reliability requirements, partially offset by a 2.5%14.7% decrease in the average cost of fuel. The decreases were partially offset by a 0.5% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.fuel resulting from lower coal and natural gas prices.
Purchased Power – Non-Affiliates
In the thirdfirst quarter 2016,2017, purchased power expense from non-affiliates was $33$32 million compared to $26$30 million for the corresponding period in 2015.2016. The increase was primarily due to a 26.5%39.0% increase in the average cost per KWH purchased primarily resulting from higher fuel costs associated with external purchases, partially offset by a 14.8% decrease in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 6.6% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.
For year-to-date 2016, purchased power expense from non-affiliates was $95 million compared to $76 million for the corresponding period in 2015. The increase was primarily due to a 46.6% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 21.0% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.increased Gulf Power 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 electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – AffiliatesOther Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $7 | | 9.1 |
In the thirdfirst quarter 2016, purchased power expense from affiliates was $32017, other operations and maintenance expenses were $84 million compared to $4$77 million for the corresponding period in 2015.2016. The decreaseincrease was primarily due to expenses at generating facilities associated with environmental compliance and routine and planned maintenance.
Environmental compliance expenses did not have a 54.9% decrease insignificant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the volumefinancial statements of KWHs purchased due to an increase in coal-fired Gulf Power generation committed to serve territorial loads, partially offset by a 67.4% increaseunder "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the average cost per KWH purchased due to higher power pool interchange rates.Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2016, purchased power expense from affiliatesDepreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(20) | | (52.6) |
In the first quarter 2017, depreciation and amortization was $9$18 million compared to $22$38 million for the corresponding period in 2015.2016. The decrease was primarily due to $20 million more of a 54.6% decreasereduction in depreciation in the volume of KWHs purchased due to lower territorial loads and a 10.8% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower fuel prices and lower off-peak energy prices of renewable market resources.
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 purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (4.4) | | $(35) | | (12.8) |
In the thirdfirst quarter 2016, other operations and maintenance expenses were $86 million2017 compared to $90 million for the corresponding period in 2015. For year-to-date 2016, other operations and maintenance expenses were $239 million compared to $274 million for the corresponding period in 2015. These decreases were primarily due to decreases in routine and planned maintenance expenses at generating facilities and lower expenses related to marketing programs.
Expenses from marketing programs do not have a significant impact on earnings since they are generally offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 22.5 | | $29 | | 29.0 |
In the third quarter 2016, depreciation and amortization was $49 million compared to $40 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $129 million compared to $100 million for the corresponding period in 2015. The increases were primarily due to $7 million and $20 million less of a reduction in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), in the third quarter and year-to-date 2016, respectively, compared to the corresponding periods in 2015. In the third quarter 2016, and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero. Also contributing to the increases were property additions at generation, transmission, and distribution facilities placed in service in 2015.
. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Income (Expense), NetTaxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | N/M | | $(12) | | N/M |
N/M - Not meaningful |
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(6) | | (30.0) |
In the thirdfirst quarter 20162017,other income (expense), net was $(2)taxes were $14 million compared to $2$20 million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net2016. This change was $(4) million compared to $8 million for the corresponding period in 2015. These changes were primarily due to lower AFUDC relatedthe income tax benefit associated with the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Rate Case Settlement Agreement. This decrease was partially offset by higher pre-tax earnings, excluding the write-down. See Note (B) to environmental control projects at generating facilities and transmission projects placed in service in 2015.the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity.providing electric service. These factors include Gulf Power'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, whichconsidering, 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. 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 Gulf Power's service territory, the successful remarketing of wholesale capacity as current contracts expire, and the outcome of the 2016 Rate Case related to Gulf Power's ownership of Plant Scherer Unit 3.territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
basis or through market-based contracts. 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. Gulf Power'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 regulatorylegislative or legislativeregulatory 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 adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS),revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Gulf Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016,planned reconsideration, the EPA issued proposed revisionsalso announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to the regional haze regulations. that effect.
The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
On September 6, 2016,March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA designated all remaining areas within Gulf Power's service territory as attainmentto review the Clean Power Plan and final greenhouse gas emission standards for the 2012 annual fine particulate matter NAAQS.
On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Mississippinew, modified, and removing Florida from the CSAPR program.reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate impactoutcome of this rule will depend on the outcome of any legal challenges and implementation at the state level andmatter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power'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 base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's ownership of Plant Scherer Unit 3 and consist of both capacity and energy sales. Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of the unit provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The ultimate outcome of this matter cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolved through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earnings in future years until Gulf Power is able to find a suitable alternative related to this asset.
Retail Base Rate Cases
The 2013 Rate Case Settlement Agreement 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 may not 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 the thirdfirst quarter 20162017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and in accordancethree of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the 2013terms of the 2017 Rate Case Settlement Agreement, Gulf Power reversed reductions previouslywill, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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, which was recorded to depreciation. As a result, forin the first nine monthsquarter 2017. The remaining issues related to the inclusion of 2016, the net reductionGulf Power's investment in depreciation was zero.
On October 12, 2016, Gulf Power filed the 2016 Rate Case with the Florida PSC requesting an increasePlant Scherer Unit 3 in retail rates and chargeshave been resolved as a result of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. TheRate Case Settlement Agreement, including recoverability of thecertain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case inunit through the second quarter 2017. Gulf Power has requested that the increase in base rates, ifenvironmental cost recovery clause rate approved by the Florida PSC become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.November 2016.
Cost Recovery Clauses
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. See Note (B) to the Condensed Financial Statements herein for additional information.
On November 2, 2016,As discussed previously, the Florida PSC approved2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effectinclusion of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decidedapproved by the Florida PSC in theNovember 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Renewables
The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.
On October 11, 2016, the Florida PSC preliminarily approved an energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
was made.
Other Matters
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) on March 31, 2016. Gulf Power filed a petition with the Florida PSC requesting permission to recover 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. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power'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 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 Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofGulf PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein 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
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Gulf Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Gulf Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Gulf Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Gulf Power has not elected its transition method.
On February 25, 2016,March 10, 2017, the FASB issued ASU No. 2016-02,2017-07, Leases(Topic 842)Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2016-02)2017-07). ASU 2016-022017-07 requires lesseesthat 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 recognize onbe separately presented in the balance sheet a lease liability and a right-of-use assetincome statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all leases.cost components remain eligible for capitalization under FERC regulations. ASU 2016-02 also changes2017-07 will be applied retrospectively for the recognition, measurement, and presentation of expense associated with leasesthe service cost component and provides clarification regarding the identification of certainother 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, with early adoption permitted. Gulf Power is currently evaluatingnet periodic pension and postretirement benefit costs in the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Gulf Power's balance sheet.
On March 30, 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. Most
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
significantly, 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. Gulf Power currently recognizes any excess tax benefitsThe capitalization of the service cost component of net periodic pension and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital.postretirement benefit costs in assets will be applied on a prospective basis. ASU 2016-092017-07 is effective for fiscal yearsannual periods beginning after December 15, 2016. Early adoption is permitted and2017, including interim periods within those annual periods. Gulf Power intendsis currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to adopt theresult in a decrease in operating income and an increase in other income for 2018. The adoption of ASU in the fourth quarter 2016. The adoption2017-07 is not expected to have a material impact on the results of operations,Gulf Power's financial position, or cash flows of Gulf Power.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at September 30, 2016.March 31, 2017. Gulf Power 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $373$50 million for the first ninethree months of 20162017 compared to $411$132 million for the corresponding period in 2015.2016. The $38$82 million decrease in net cash was primarily due to a decrease in wholesale capacity revenue, partially offset by a federal income tax refund.refund received in 2016, as well as decreases in cash flows associated with accrued taxes, cost recovery clauses as a result of decreased revenue collection, and changes in accounts receivable in 2017 compared to 2016. Net cash used for investing activities totaled $127$57 million in the first ninethree months of 20162017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $251$17 million for the first ninethree months of 20162017 primarily due to a decrease in notes payable and the redemption of long-term debt, payment of common stock dividends, and a decrease in notes payable.partially offset by proceeds from the issuance of common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include decreasesan increase in common stock of $125$175 million, a decrease in long-term debt due tonotes payable of $168 million, primarily funded with the common stock issuance, and a redemption and $109 milliondecrease in net property, plant, and equipment primarily due to the retirementwrite-down of Gulf Power's ownership of Plant Smith Units 1 and 2 and an increase in accumulated provisionScherer Unit 3. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for depreciation primarily due to environmental control projects at generating facilities and transmission projects placed in service in 2015.additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $195$92 million will be required through September 30, 2017March 31, 2018 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.
Gulf Power's construction program is currently estimated to total $0.2 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
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 statutes 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 programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Sources of Capital
Gulf Power 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, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
Gulf Power's current liabilities frequently exceed current assets because of the continued 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. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.
At September 30, 2016,March 31, 2017, Gulf Power had approximately $69$32 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016March 31, 2017 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 | |
| 2017 | | 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 50 |
| | $ | 65 |
| | $ | 165 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| | $ | 70 |
| 85 |
| | $ | 195 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 25 |
| | $ | 70 |
|
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Gulf Power 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, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power 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 Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016March 31, 2017 was approximately $82 million. In addition, at September 30, 2016,March 31, 2017, Gulf Power had approximately $21$86 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Gulf Power 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 Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. 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 in the balance sheets.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
| | | | | Short-term Debt at September 30, 2016 | | Short-term Debt During the Period(*) | | Short-term Debt at March 31, 2017 | | 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) |
| Commercial paper | | $ | — |
| | — | % | | $ | 35 |
| | 0.8 | % | | $ | 88 |
| | $ | — |
| | — | % | | $ | 29 |
| | 1.1 | % | | $ | 168 |
|
| Short-term bank debt | | 100 |
| | 1.3 | % | | 100 |
| | 1.2 | % | | 100 |
| | 100 |
| | 1.7 | % | | 100 |
| | 1.5 | % | | 100 |
|
| Total | | $ | 100 |
| | 1.3 | % | | $ | 135 |
| | 1.1 | % | | | | $ | 100 |
| | 1.7 | % | | $ | 129 |
| | 1.4 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.March 31, 2017. |
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
Credit Rating Risk
At March 31, 2017, Gulf Power 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.
The maximum potential collateral requirements under these contracts at September 30, 2016March 31, 2017 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 192 |
| $ | 167 |
|
| Below BBB- and/or Baa3 | $ | 630 |
| $ | 564 |
|
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 Gulf Power 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 Gulf Power) from stable to negative.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the thirdfirst quarter and year-to-date 20162017 has not changed materially compared to the December 31, 20152016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity had been limited because its long-term sales agreements shifted substantially all fuel cost responsibility to the purchaser. However, Gulf Power is exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.
In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolves the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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.
For an in-depthadditional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 is expected to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
Financing Activities
In May 2016,January 2017, Gulf Power redeemed $125 million aggregate principal amountissued 1,750,000 shares of its Series 2011A 5.75% Senior Notes due June 1, 2051.common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.
Also in May 2016,In March 2017, Gulf Power entered into an 11-monthextended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were usedLIBOR from April 2017 to repay existing indebtedness and for working capital and other general corporate purposes.October 2017.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power 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.
its $150 million aggregate outstanding preference stock during 2017.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Retail revenues | $ | 263 |
| | $ | 244 |
| | $ | 652 |
| | $ | 601 |
| $ | 200 |
| | $ | 183 |
|
| Wholesale revenues, non-affiliates | 78 |
| | 76 |
| | 198 |
| | 216 |
| 62 |
| | 60 |
|
| Wholesale revenues, affiliates | 7 |
| | 18 |
| | 23 |
| | 63 |
| 5 |
| | 9 |
|
| Other revenues | 4 |
| | 3 |
| | 12 |
| | 13 |
| 5 |
| | 5 |
|
| Total operating revenues | 352 |
| | 341 |
| | 885 |
| | 893 |
| 272 |
| | 257 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 112 |
| | 130 |
| | 268 |
| | 359 |
| 78 |
| | 76 |
|
| Purchased power, non-affiliates | 3 |
| | 1 |
| | 4 |
| | 5 |
| 1 |
| | — |
|
| Purchased power, affiliates | 5 |
| | 1 |
| | 14 |
| | 6 |
| 7 |
| | 5 |
|
| Other operations and maintenance | 74 |
| | 63 |
| | 211 |
| | 206 |
| 74 |
| | 69 |
|
| Depreciation and amortization | 30 |
| | 38 |
| | 114 |
| | 95 |
| 40 |
| | 38 |
|
| Taxes other than income taxes | 31 |
| | 24 |
| | 81 |
| | 71 |
| 26 |
| | 26 |
|
| Estimated loss on Kemper IGCC | 88 |
| | 150 |
| | 222 |
| | 182 |
| 108 |
| | 53 |
|
| Total operating expenses | 343 |
| | 407 |
| | 914 |
| | 924 |
| 334 |
| | 267 |
|
| Operating Income (Loss) | 9 |
| | (66 | ) | | (29 | ) | | (31 | ) | |
| Operating Loss | | (62 | ) | | (10 | ) |
| Other Income and (Expense): | | | | | | | | | | |
| Allowance for equity funds used during construction | 31 |
| | 29 |
| | 90 |
| | 82 |
| 35 |
| | 29 |
|
| Interest expense, net of amounts capitalized | (15 | ) | | (13 | ) | | (46 | ) | | 6 |
| (19 | ) | | (16 | ) |
| Other income (expense), net | (1 | ) | | (2 | ) | | (4 | ) | | (5 | ) | (1 | ) | | (2 | ) |
| Total other income and (expense) | 15 |
| | 14 |
| | 40 |
| | 83 |
| 15 |
| | 11 |
|
| Earnings (Loss) Before Income Taxes | 24 |
| | (52 | ) | | 11 |
| | 52 |
| (47 | ) | | 1 |
|
| Income taxes (benefit) | (2 | ) | | (31 | ) | | (29 | ) | | (11 | ) | (27 | ) | | (10 | ) |
| Net Income (Loss) | 26 |
| | (21 | ) | | 40 |
| | 63 |
| (20 | ) | | 11 |
|
| Dividends on Preferred Stock | — |
| | — |
| | 1 |
| | 1 |
| — |
| | — |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 26 |
| | $ | (21 | ) | | $ | 39 |
| | $ | 62 |
| $ | (20 | ) | | $ | 11 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Net Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 63 |
| $ | (20 | ) | | $ | 11 |
|
| 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 |
| | 1 |
| |
| Changes in fair value, net of tax of $- and $-, respectively | | 1 |
| | — |
|
| Total other comprehensive income (loss) | — |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
|
| Comprehensive Income (Loss) | $ | 26 |
| | $ | (21 | ) | | $ | 40 |
| | $ | 64 |
| $ | (19 | ) | | $ | 11 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) | | | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 40 |
| | $ | 63 |
| |
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Net income (loss) | | $ | (20 | ) | | $ | 11 |
|
| Adjustments to reconcile net income to net cash used for operating activities — | | | | |
| Depreciation and amortization, total | 115 |
| | 94 |
| 49 |
| | 39 |
|
| Deferred income taxes | 34 |
| | 518 |
| (47 | ) | | (4 | ) |
| Investment tax credits | — |
| | 25 |
| |
| Allowance for equity funds used during construction | (90 | ) | | (82 | ) | (35 | ) | | (29 | ) |
| Regulatory assets associated with Kemper IGCC | (13 | ) | | (56 | ) | |
| Estimated loss on Kemper IGCC | 222 |
| | 182 |
| 108 |
| | 53 |
|
| Income taxes receivable, non-current | — |
| | (544 | ) | |
| Other, net | 12 |
| | 7 |
| (3 | ) | | (4 | ) |
| Changes in certain current assets and liabilities — | | | | | | |
| -Prepaid income taxes | 38 |
| | (1 | ) | |
| -Other current assets | 7 |
| | 4 |
| 18 |
| | 43 |
|
| -Accounts payable | 5 |
| | (32 | ) | (35 | ) | | (22 | ) |
| -Accrued taxes | 95 |
| | 24 |
| (46 | ) | | (60 | ) |
| -Accrued compensation | | (22 | ) | | (16 | ) |
| -Over recovered regulatory clause revenues | (20 | ) | | 59 |
| (12 | ) | | 9 |
|
| -Mirror CWIP | — |
| | 99 |
| |
| -Customer liability associated with Kemper refunds | (73 | ) | | — |
| — |
| | (51 | ) |
| -Other current liabilities | — |
| | (11 | ) | 5 |
| | 8 |
|
| Net cash provided from operating activities | 372 |
| | 349 |
| |
| Net cash used for operating activities | | (40 | ) | | (23 | ) |
| Investing Activities: | | | | | | |
| Property additions | (592 | ) | | (626 | ) | (186 | ) | | (197 | ) |
| Construction payables | (25 | ) | | (31 | ) | — |
| | (7 | ) |
| Capital grant proceeds | 137 |
| | — |
| |
| Payments pursuant to LTSAs | | 1 |
| | (5 | ) |
| Other investing activities | (29 | ) | | (29 | ) | (5 | ) | | (5 | ) |
| Net cash used for investing activities | (509 | ) | | (686 | ) | (190 | ) | | (214 | ) |
| Financing Activities: | | | | | | |
| Increase in notes payable, net | — |
| | 475 |
| 9 |
| | — |
|
| Proceeds — | | | | | | |
| Capital contributions from parent company | 227 |
| | 153 |
| |
| Long-term debt to parent company | 200 |
| | — |
| — |
| | 200 |
|
| Other long-term debt | 900 |
| | — |
| — |
| | 900 |
|
| Short-term borrowings | — |
| | 30 |
| 4 |
| | — |
|
| Redemptions — | | | | | | |
| Short-term borrowings | (475 | ) | | (5 | ) | — |
| | (475 | ) |
| Long-term debt to parent company | (225 | ) | | — |
| |
| Other long-term debt | (425 | ) | | (350 | ) | — |
| | (425 | ) |
| Other financing activities | (4 | ) | | (3 | ) | (1 | ) | | (2 | ) |
| Net cash provided from financing activities | 198 |
| | 300 |
| 12 |
| | 198 |
|
| Net Change in Cash and Cash Equivalents | 61 |
| | (37 | ) | (218 | ) | | (39 | ) |
| Cash and Cash Equivalents at Beginning of Period | 98 |
| | 133 |
| 224 |
| | 98 |
|
| Cash and Cash Equivalents at End of Period | $ | 159 |
| | $ | 96 |
| $ | 6 |
| | $ | 59 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
Interest (paid $72 and $58, net of $36 and $52 capitalized for 2016
and 2015, respectively) | $ | 36 |
| | $ | 6 |
| |
Interest (paid $25 and $22, net of $12 and $10 capitalized for 2017
and 2016, respectively) | | $ | 13 |
| | $ | 12 |
|
| Income taxes, net | (231 | ) | | (55 | ) | — |
| | (24 | ) |
| Noncash transactions — | | | | |
| Accrued property additions at end of period | 80 |
| | 83 |
| |
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | 301 |
| |
| Noncash transactions — Accrued property additions at end of period | | 78 |
| | 97 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 159 |
| | $ | 98 |
| | $ | 6 |
| | $ | 224 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 39 |
| | 26 |
| | 26 |
| | 29 |
|
| Unbilled revenues | | 47 |
| | 36 |
| | 38 |
| | 42 |
|
| Income taxes receivable, current | | — |
| | 20 |
| | 544 |
| | 544 |
|
| Other accounts and notes receivable | | 6 |
| | 10 |
| | 17 |
| | 14 |
|
| Affiliated | | 17 |
| | 20 |
| | 14 |
| | 15 |
|
| Fossil fuel stock | | 96 |
| | 104 |
| | 83 |
| | 100 |
|
| Materials and supplies | | 75 |
| | 75 |
| | 78 |
| | 76 |
|
| Other regulatory assets, current | | 118 |
| | 95 |
| | 113 |
| | 115 |
|
| Prepaid income taxes | | — |
| | 39 |
| |
| Other current assets | | 10 |
| | 8 |
| | 3 |
| | 8 |
|
| Total current assets | | 567 |
| | 531 |
| | 922 |
| | 1,167 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 4,835 |
| | 4,886 |
| | 4,963 |
| | 4,865 |
|
| Less accumulated provision for depreciation | | 1,259 |
| | 1,262 |
| |
| Less: Accumulated provision for depreciation | | | 1,303 |
| | 1,289 |
|
| Plant in service, net of depreciation | | 3,576 |
| | 3,624 |
| | 3,660 |
| | 3,576 |
|
| Construction work in progress | | 2,525 |
| | 2,254 |
| | 2,570 |
| | 2,545 |
|
| Total property, plant, and equipment | | 6,101 |
| | 5,878 |
| | 6,230 |
| | 6,121 |
|
| Other Property and Investments | | 12 |
| | 11 |
| | 12 |
| | 12 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Deferred charges related to income taxes | | 330 |
| | 290 |
| | 382 |
| | 361 |
|
| Other regulatory assets, deferred | | 510 |
| | 525 |
| | 520 |
| | 518 |
|
| Income taxes receivable, non-current | | 544 |
| | 544 |
| |
| Other deferred charges and assets | | 101 |
| | 61 |
| | 22 |
| | 56 |
|
| Total deferred charges and other assets | | 1,485 |
| | 1,420 |
| | 924 |
| | 935 |
|
| Total Assets | | $ | 8,165 |
| | $ | 7,840 |
| | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholder's Equity | | At September 30, 2016 | | At December 31, 2015 | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 343 |
| | $ | 728 |
| |
| Securities due within one year — | | | | | |
| Parent | | | $ | — |
| | $ | 551 |
|
| Other | | | 1,328 |
| | 78 |
|
| Notes payable | | 25 |
| | 500 |
| | 36 |
| | 23 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 92 |
| | 85 |
| | 44 |
| | 62 |
|
| Other | | 126 |
| | 135 |
| | 112 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
| | 16 |
| | 16 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 110 |
| | — |
| |
| Other accrued taxes | | 75 |
| | 85 |
| |
| Accrued taxes | | | 51 |
| | 99 |
|
| Unrecognized tax benefits | | | 385 |
| | 383 |
|
| Accrued interest | | 20 |
| | 18 |
| | 50 |
| | 46 |
|
| Accrued compensation | | 21 |
| | 26 |
| | 20 |
| | 42 |
|
| Asset retirement obligations, current | | 36 |
| | 22 |
| | 27 |
| | 32 |
|
| Over recovered regulatory clause liabilities | | 76 |
| | 96 |
| | 39 |
| | 51 |
|
| Customer liability associated with Kemper refunds | | 1 |
| | 73 |
| |
| Other current liabilities | | 37 |
| | 52 |
| | 22 |
| | 20 |
|
| Total current liabilities | | 978 |
| | 1,836 |
| | 2,130 |
| | 1,538 |
|
| Long-term Debt: | | | | | | | | |
| Long-term debt, affiliated | | 551 |
| | 576 |
| |
| Long-term debt to parent | | | 551 |
| | — |
|
| Long-term debt, non-affiliated | | 2,161 |
| | 1,310 |
| | 1,172 |
| | 2,424 |
|
| Total Long-term Debt | | 2,712 |
| | 1,886 |
| | 1,723 |
| | 2,424 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 823 |
| | 762 |
| | 729 |
| | 756 |
|
| Deferred credits related to income taxes | | 7 |
| | 8 |
| |
| Employee benefit obligations | | 146 |
| | 153 |
| | 113 |
| | 115 |
|
| Asset retirement obligations, deferred | | 154 |
| | 154 |
| | 148 |
| | 146 |
|
| Unrecognized tax benefits | | 382 |
| | 368 |
| |
| Other cost of removal obligations | | 172 |
| | 165 |
| | 172 |
| | 170 |
|
| Other regulatory liabilities, deferred | | 76 |
| | 71 |
| | 78 |
| | 84 |
|
| Other deferred credits and liabilities | | 54 |
| | 45 |
| | 36 |
| | 26 |
|
| Total deferred credits and other liabilities | | 1,814 |
| | 1,726 |
| | 1,276 |
| | 1,297 |
|
| Total Liabilities | | 5,504 |
| | 5,448 |
| | 5,129 |
| | 5,259 |
|
| Redeemable Preferred Stock | | 33 |
| | 33 |
| | 33 |
| | 33 |
|
| 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 | | 3,124 |
| | 2,893 |
| | 3,526 |
| | 3,525 |
|
| Accumulated deficit | | (528 | ) | | (566 | ) | | (635 | ) | | (616 | ) |
| Accumulated other comprehensive loss | | (6 | ) | | (6 | ) | | (3 | ) | | (4 | ) |
| Total common stockholder's equity | | 2,628 |
| | 2,359 |
| | 2,926 |
| | 2,943 |
|
| Total Liabilities and Stockholder's Equity | | $ | 8,165 |
| | $ | 7,840 |
| | $ | 8,088 |
| | $ | 8,235 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Mississippi Power 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 Mississippi Power's business of selling electricity.providing electric service. These factors include Mississippi Power'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 expenditures required for maintenance.maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
In 2010,Mississippi Power continues to progress toward completing the Mississippi PSC issued a CPCN authorizing the acquisition, construction and operation of the Kemper IGCC. The certificated cost estimatestart-up of the Kemper IGCC, establishedwhich was approved by the Mississippi PSC was $2.4 billion within 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 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). On April 8, 2016, Mississippi Power received
The current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE for the Kemper IGCCreceived on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts forto customers.
Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur by December 31, 2016. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.82 billion, which includes approximately $5.52 billion of costs subject to the construction cost cap and is net of the Additional DOE Grants. 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 Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $88$108 million ($5467 million after tax) in the thirdfirst quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016.2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63$2.87 billion ($1.631.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.
In addition, duringMarch 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the start-up and commissioning process, Mississippi Power is identifying potential$2.88 billion cost cap. Additional improvement projects thatto enhance plant performance, safety, and/or operations ultimately may be completed subsequent to placingafter the remainder of the Kemper IGCC is placed in service. IfThese projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The combined cycle and the associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. On July 27, 2016,Upon placing the Mississippi Supreme Court (Court) dismissed Greenleaf CO2 Solutions, LLC’s (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appealremainder of the In-Service Asset Rate Order.
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016,plant in service, Mississippi Power made a required compliance filing, which included a review and explanation of differences betweenwill be focused primarily on completing the Kemper IGCC project estimate set forth in the 2010 CPCN proceeding and the most recent Kemper IGCC project estimate, as well as comparisons of currentregulatory cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.recovery process.
Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until therequired to file a rate case to address Kemper IGCC cost recovery approachby June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is finalized, which are expectedincluded in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be material.filed with the Mississippi PSC and expected subsequent wholesale MRA rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
In connection with the 2017 Rate Case, Mississippi Power expects to request authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is requireddeveloping both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to fileprepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its next rate request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related to cost recovery forlegal challenges), the Kemper IGCC by June 3, 2017. The ultimate outcome of these matters cannot now be determined at this time.
Southern Company and Mississippi Power are defendantsbut could result in two lawsuitsfurther charges that allege improper disclosure of important facts about the Kemper IGCC. While Mississippi Power believes that these lawsuits are without merit, an adverse outcome could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. In addition, the SEC is conducting a formal investigation
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.
As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt. In addition, if the Kemper IGCC does not go into service by December 31, 2016,financial statement presentation contemplates continuation of Mississippi Power would have to repay approximately $250 million of tax benefits receivedas a going concern as a result of quarterly income tax estimates through September 30, 2016.Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the Kemper IGCC, Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC.indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed return. In addition to the PEP performance indicators,ROE. Mississippi Power also focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Mississippi Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $47 | | N/M | | $(23) | | (37.1) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(31) | | N/M |
N/M - Not meaningful
Mississippi Power's net incomeloss after dividends on preferred stock for the thirdfirst quarter 20162017 was $26$20 million compared to a net lossincome of $21$11 million for the corresponding period in 2015.2016. The increasedecrease in net income was primarily related to lowerhigher pre-tax charges of $88$108 million ($5467 million after tax) in the third quarter 20162017 compared to pre-tax charges of $150$53 million ($9333 million after tax) in the third quarter 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The increase in net income was also due to an increase in retail revenues and a decrease in depreciation and amortization, partially offset by an increase in other operations and maintenance expenses.
For year-to-date 2016 net income after dividends on preferred stock was $39 million compared to $62 million for the corresponding period in 2015. The decrease was primarily related to a decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015, higher depreciation and amortization, and higher pre-tax charges of $222 million ($137 million after tax) in 2016 compared to pre-tax charges of $182 million ($112 million after tax) in 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was partially offset by an increase in retail revenues.operating revenues and AFUDC equity.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Retail Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 7.8 | | $51 | | 8.5 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $17 | | 9.3 |
In the thirdfirst quarter 2016,2017, retail revenues were $263$200 million compared to $244$183 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $652 million compared to $601 million for the corresponding period in 2015.2016.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of the changes in retail revenues were as follows:
| | | | Third Quarter 2016 | | Year-to-Date 2016 | First Quarter 2017 |
| | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) |
| Retail – prior year | $ | 244 |
| | | | $ | 601 |
| | | $ | 183 |
| | |
| Estimated change resulting from – | | | | | | | | | | |
| Rates and pricing | 8 |
| | 3.3 |
| | 66 |
| | 11.0 |
| 12 |
| | 6.6 |
|
| Sales growth (decline) | (3 | ) | | (1.3 | ) | | (2 | ) | | (0.3 | ) | 4 |
| | 2.1 |
|
| Weather | 7 |
| | 2.9 |
| | 5 |
| | 0.8 |
| (5 | ) | | (2.7 | ) |
| Fuel and other cost recovery | 7 |
| | 2.9 |
| | (18 | ) | | (3.0 | ) | 6 |
| | 3.3 |
|
| Retail – current year | $ | 263 |
| | 7.8 | % | | $ | 652 |
| | 8.5 | % | $ | 200 |
| | 9.3 | % |
Revenues associated with changes in rates and pricing increased in the thirdfirst quarter and year-to-date 20162017 when compared to the corresponding periodsperiod in 2015,2016, primarily due to an ECO Plan rate increase implemented in the implementation of rates for certain Kemper IGCC in-service assets. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.third quarter 2016.
Revenues attributable to changes in sales decreased inincreased for the thirdfirst quarter 20162017 when compared to the corresponding period in 2015.2016. Weather-adjusted KWH sales to residential andcustomers increased 1.3% due to higher customer usage offset by a decline in the number of customers. Weather-adjusted KWH sales to commercial customers decreased 6.7% and 0.9%, respectively, in the third quarter 20160.1% due to decreasedlower customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 1.7% in the third quarter 2016increased 0.6% primarily due to an unplanned outage by a large customer.
Revenues attributable to changescustomer in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 2.6% and 1.5%, respectively, due to decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 0.7% primarily due to an unplanned outage by a large customer.
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 discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential KWH sales decreased 0.8%, weather-adjusted KWH sales to commercial customers increased 0.6%, and KWH sales to industrial customers were relatively flat as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues increased in the thirdfirst quarter 20162017 when compared to the corresponding period in 2015,2016, primarily as a result of revised ECO Plan rates which became effective with the first billing cycle for September 2016, partially offset by lowerhigher recoverable fuel costs. Fuel and other cost recovery revenues decreased for year-to-date 2016 when compared to the corresponding period in 2015, primarily as a result of lower recoverable fuel costs, partially offset by revised ECO Plan rates which became effective with the first billing cycle for September 2016. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 2.6 | | $(18) | | (8.3) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power'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 have a significant impact on net income. In addition, Mississippi Power 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and – FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.
For year-to-date 2016, wholesale revenues from sales to non-affiliates were $198 million compared to $216 million for the corresponding period in 2015. The decrease was primarily due to a $16 million decrease in energy revenues primarily resulting from lower natural gas prices and decreased usage primarily resulting from milder weather.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (61.1) | | $(40) | | (63.5) |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(4) | | (44.4) |
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 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 the thirdfirst quarter 2016,2017, wholesale revenues from sales to affiliates were $7$5 million compared to $18$9 million for the corresponding period in 2015.2016. The decrease was due to a decrease in KWH sales primarily due to availability of lower cost alternatives.
For year-to-date 2016, wholesale revenues from sales to affiliates were $23 million compared to $63 million for the corresponding period in 2015. The decrease was due to a $35$5 million decrease in KWH sales primarily due to the availability of lower cost alternatives andoffset by a $5$1 million decreaseincrease associated with lowerhigher natural gas prices.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
| | | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | First Quarter 2017
vs.
First Quarter 2016 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) |
| Fuel | | $ | (18 | ) | | (13.8) | | $ | (91 | ) | | (25.3) | $ | 2 |
| | 2.6 |
| Purchased power – non-affiliates | | 2 |
| | N/M | | (1 | ) | | (20.0) | 1 |
| | N/M |
| Purchased power – affiliates | | 4 |
| | N/M | | 8 |
| | N/M | 2 |
| | 40.0 |
| Total fuel and purchased power expenses | | $ | (12 | ) | | $ | (84 | ) | | $ | 5 |
| |
N/M - Not meaningful
In the thirdfirst quarter 2016,2017, total fuel and purchased power expenses were $120$86 million compared to $132$81 million for the corresponding period in 2015.2016. The decrease was primarily due to a net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales.
For year-to-date 2016, total fuel and purchased power expenses were $286 million compared to $370 million for the corresponding period in 2015. The decreaseincrease was due to a $49$15 million increase in natural gas prices offset by a $10 million net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales and milder weather and a $35 million decrease due to lower natural gas prices.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 Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | | Third Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 | First Quarter 2017 | | First Quarter 2016 |
Total generation (in millions of KWHs) | 4,255 | | 4,681 | | 11,570 | | 13,136 | 3,161 | | 3,588 |
Total purchased power (in millions of KWHs) | 288 | | 121 | | 877 | | 427 | 242 | | 261 |
Sources of generation (percent) – | | | |
| Coal | 10 | | 19 | | 9 | | 20 | 9 | | 11 |
| Gas | 90 | | 81 | | 91 | | 80 | 91 | | 89 |
Cost of fuel, generated (in cents per net KWH) – | | |
| Coal | 4.02 | | 3.81 | | 4.09 | | 3.70 | 3.33 | | 3.55 |
| Gas | 2.64 | | 2.72 | | 2.34 | | 2.70 | 2.65 | | 2.15 |
Average cost of fuel, generated (in cents per net KWH) | 2.79 | | 2.93 | | 2.50 | | 2.91 | 2.71 | | 2.32 |
Average cost of purchased power (in cents per net KWH) | 2.59 | | 2.21 | | 2.04 | | 2.42 | 3.33 | | 2.17 |
Fuel
In the thirdfirst quarter 2016,2017, total fuel expense was $112$78 million compared to $130$76 million for the corresponding period in 2015.2016. The decreaseincrease was due to a 10.2%17% increase in the average cost of fuel per KWH generated primarily due to a 23% higher cost of natural gas offset by a 12% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 4.8% decrease in the average cost of fuel per KWH generated primarily due to a 2.7% lower cost of natural gas.sales.
For year-to-date 2016, total fuel expense was $268 million compared to $359 million for the corresponding period in 2015. The decrease was due to a 12.9% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 14.2% decrease in the average cost of fuel per KWH generated primarily due to a 13.6% lower cost of natural gas.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power - Non-Affiliates
For year-to-date 2016, purchased power expense from non-affiliates was $4 million compared to $5 million for the corresponding period in 2015. The decrease was primarily due to a 43.1% decrease in the average cost per KWH purchased due to lower energy costs from available gas-fired resources, partially offset by a 49.0% increase in the volume of KWHs purchased due to the availability of lower cost energy.
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
In the thirdfirst quarter 2016,2017, purchased power expense from affiliates was $5$7 million compared to $1$5 million for the corresponding period in 2015.2016. The increase was primarily due to a 234.7% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost and a 9.9% increase in the average cost per KWH purchased due to higher power pool interchange rates associated with higher natural gas prices.
For year-to-date 2016, purchased power expense from affiliates was $14 million compared to $6 million for the corresponding period in 2015. The increase was primarily due to a 163.8%35% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost, partially offset by a 5.9%6% decrease in the average cost per KWH purchased due to lower power pool interchange ratesprimarily as a result of lower fuel prices.
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 purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $11 | | 17.5 | | $5 | | 2.4 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $5 | | 7.2 |
In the thirdfirst quarter 2016,2017, other operations and maintenance expenses were $74 million compared to $63$69 million for the corresponding period in 2015.2016. The increase was primarily due to a $7$3 million increase in amortization of prior operations and maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in connection with interim ratesexpense deferrals associated with the Kemper IGCC in-service assets implemented in September 2015 and a $4$2 million increase in transmission and distribution overhead line maintenance and vegetation management expenses.
For year-to-date 2016, other operations andgeneration maintenance expenses, were $211 million compared to $206 million for the corresponding period in 2015. The increase was primarily due to a $23 million increase in maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in connection with interim rates associated with the Kemper IGCC in-service assets implemented in September 2015, partially offset by a $15 million decrease in generation outage costs and a $4 million decrease primarily related to pension costs.including scheduled outages.
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. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (21.1) | | $19 | | 20.0 |
In the third quarter 2016, depreciation and amortization was $30 million compared to $38 million for the corresponding period in 2015. The decrease was primarily due to a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016, partially offset by an increase in depreciation and amortization of $9 million primarily related to the In-Service Asset Rate Order, ECO Plan, MATS rule compliance, and additional plant in service assets.
For year-to-date 2016, depreciation and amortization was $114 million compared to $95 million for the corresponding period in 2015. The increase was primarily due to additional regulatory asset amortization of $16 million related to the In-Service Asset Rate Order, ECO Plan, and MATS rule compliance, $12 million primarily due to Kemper IGCC deferrals, and $8 million of depreciation for additional plant in service assets, primarily the Plant Daniel scrubbers. These increases were partially offset by a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016.
See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. Also, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 29.2 | | $10 | | 14.1 |
In the third quarter 2016, taxes other than income taxes were $31 million compared to $24 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $81 million compared to $71 million for the corresponding period in 2015. The increases were primarily due to increases in ad valorem taxes of $4 million and $6 million for the third quarter and year-to-date 2016, respectively, due to an increase in the assessed value of property as well as increases in franchise taxes of $3 million and $4 million for the third quarter and year-to-date 2016, respectively.
The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(62) | | (41.3) | | $40 | | 22.0 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $55 | | N/M |
N/M - Not meaningful
In the thirdfirst quarters of 20162017 and 2015,2016, estimated probable losses on the Kemper IGCC of $88$108 million and $150 million, respectively, were recorded at Mississippi Power. For year-to-date 2016 and year-to-date 2015, estimated probable losses on the Kemper IGCC of $222 million and $182$53 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 6.9 | | $8 | | 9.8 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $6 | | 20.7 |
In the thirdfirst quarter of 2016,2017, AFUDC equity was $31$35 million compared to $29 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $90 million compared to $82 million for the corresponding period in 2015.2016. The increases were driven byincrease resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC, partially offset by placing the Plant Daniel scrubbers in service in November 2015. AFUDC.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 15.4 | | $52 | | N/M |
N/M - Not meaningful |
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $3 | | 18.8 |
In the thirdfirst quarter 2016,2017, interest expense, net of amounts capitalized was $15$19 million compared to $13$16 million for the corresponding period in 2015. The increase was related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.
For year-to-date 2016, interest expense, net of amounts capitalized was $46 million compared to $(6) million for the corresponding period in 2015.2016. The increase was primarily due to a $31amortization of $3 million decrease in deferred interest on deposits in 2015 resulting fromassociated with the termination of an asset purchase agreement between Mississippi PowerKemper IGCC in-service assets and SMEPA in May 2015. In addition, the increase was$1 million related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.uncertain tax positions.
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and NoteNotes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits," respectively, herein for additional information on the Mirror CWIP refund.information.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 93.5 | | $(18) | | N/M |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(17) | | N/M |
N/M - Not meaningful
In the thirdfirst quarter 2016,2017, income tax benefit was $(2)$27 million compared to $(31)$10 million for the corresponding period in 2015. The change was primarily due to the reduction in the estimated probable losses on construction of the Kemper IGCC.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2016, income tax benefit was $(29) million compared to $(11) million for the corresponding period in 2015.2016. The change was primarily due to the increase in the estimated probable losses on construction of the Kemper IGCC.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity.providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper IGCC costs not included in current rates, in a timely manner during a time of increasing costs, its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC, as well as other ongoing construction projects.PSC. Future earnings in the near term will be driven primarily by customer growth. Earnings will also depend in part, upon maintaining and growing sales, whichconsidering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. 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 Mississippi Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts.long-term wholesale agreements. 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. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule regional haze regulations,revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion,2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Mississippi Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
Also on April 25, 2016,planned reconsideration, the EPA issued proposed revisionsalso announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to the regional haze regulations. that effect.
The ultimate impactoutcome of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges andthese matters cannot be determined at this time.
Global Climate Issues
MISSISSIPPI POWER COMPANY
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
– FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information.
On October 26, 2016,March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA published ato review the Clean Power Plan and final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabamagreenhouse gas emission standards for new, modified, and Mississippi.reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate impactoutcome of this rule will depend on the outcome of any legal challenges and implementation at the state level andmatter cannot be determined at this time.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B)
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
OnIn March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA)MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement accepted by the FERC,became effective for services rendered beginning May 1, 2016, provides that base ratesresulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million.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 Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $11$18 million throughuntil the end of May 2017 when the Kemper IGCC'sIGCC is projected in-service date of December 31, 2016.
Fuel Cost Recovery
Mississippi Power 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.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery"be placed in Item 8 of the Form 10-K for additional information.service.
Retail Regulatory Matters
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power'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 recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Renewables
In November 2015,Of the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service byin 2017, one was placed in service in the secondfirst quarter 2017, andwhile the resulting energy purchasesremaining two are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.placed in service in June and July 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
Performance Evaluation Plan
On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
Energy Efficiency
On May 3,In November 2016, the Mississippi PSC issued an order approving the annualPower submitted its Energy Efficiency Cost Rider (EECR) Compliance filing, which included an anticipated reductionincrease of $1 million in annual retail revenues. On March 13, 2017, Mississippi Power amended and revised the EECR Compliance filing to request a $2 million annual increase in retail revenues for the year ending December 31, 2016.
Performance Evaluation Plan
On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
revenues. The ultimate outcome of these mattersthis matter cannot be determined at this time.
Environmental Compliance Overview Plan
On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million111
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel Cost Recovery
At September 30, 2016,March 31, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $58$27 million compared to $71$37 million at December 31, 2015.2016.
Ad Valorem Tax Adjustment
On April 7, 2017, Mississippi Power submitted its 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. The Mississippi PSC conditionally approved a decreaseultimate outcome of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC will utilize anutilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC will beis 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. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Initial 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 in August 2014 and continues to progress towards completing the2014. The remainder of the Kemper IGCC,plant, including the gasifiers and the gas clean-up facilities.facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016,Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the Kemper IGCC began testing using cleanproduction of electricity from syngas from gasifier "A"in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experiencedoff-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems. Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integratedreach sustained operation of both gasifiers will not occur by mid-November and has revised the expected in-service date forproduction of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, to December 31, 2016.including both gasifiers, will be placed in service by the end of May 2017. The remaining schedule reflects the expected time expectedneeded to achieverepair a leak in one of the particulate control devices for gasifier "A," make other minor modifications to each gasifier's ash removal systems, repair the sour water system, and establish sustained operation of both gasifiers for the production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity withfrom syngas.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2016March 31, 2017, all of which include 100% of the costs for the Kemper IGCC, are as follows:
| | | Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
| $ | 2.40 |
| | $ | 5.75 |
| | $ | 5.57 |
|
| Lignite Mine and Equipment | 0.21 |
| | 0.23 |
| | 0.23 |
| 0.21 |
| | 0.23 |
| | 0.23 |
|
CO2 Pipeline Facilities | 0.14 |
| | 0.11 |
| | 0.11 |
| 0.14 |
| | 0.12 |
| | 0.12 |
|
AFUDC(d) | 0.17 |
| | 0.75 |
| | 0.71 |
| 0.17 |
| | 0.83 |
| | 0.80 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
| — |
| | 0.05 |
| | 0.04 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
| 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
| — |
| | 0.22 |
| | 0.22 |
|
| Additional DOE Grants | — |
| | (0.14 | ) | | (0.14 | ) | — |
| | (0.14 | ) | | (0.14 | ) |
Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
| $ | 2.97 |
| | $ | 7.16 |
| | $ | 6.93 |
|
| |
| (a) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial 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 (e) for additional information. |
| |
| (d) | Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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. |
| |
| (e) | Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016.March 31, 2017. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016.March 31, 2017. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
| |
| (f) | The Current Cost Estimate and the Actual Costs include $2.87 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.09 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.23 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 and Note 6 to the financial statements of Mississippi Power under "Fuel Inventory" and "Capital Leases," respectively, in Item 8 of the Form 10-K and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70March 31, 2017, $3.73 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.63$2.95 billion), $6 million in other property and investments, $81$64 million in fossil fuel stock, $46$48 million in materials and supplies, $33$24 million in other regulatory assets, current, $177$173 million in other regulatory assets, deferred, $4$1 million in other current assets, and $9$17 million in other deferred charges and assets in the balance sheet.
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 Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $88$108 million ($5467 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. The increase to the cost estimate in the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
increased efforts related to operational readiness and challengesafter tax) in start-up and commissioning activities, includingthe first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subject toestimate above the cost cap.cap for the Kemper IGCC through March 31, 2017. The year-to-date increase to the cost estimate also includes $78in the first quarter 2017 primarily reflects $67 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016mid-March 2017 to October 31, 2016. the end of May 2017, $23 million related to start-up fuel, and $18 million primarily related to outage maintenance and operational improvements.
In addition duringto the start-up and commissioning process,current construction cost estimate, Mississippi Power is identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. TheApproximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond DecemberMay 31, 20162017 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, additionalAdditional 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 DecemberMay 31, 20162017 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 $15$16 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 $3 million per month. For additional information, see "Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein.
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. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recoveryGiven the variety of a portionpotential scenarios and the uncertainty of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recoveryoutcome of the retail portion of the Kemper IGCC is subject to the jurisdiction offuture regulatory proceedings with the Mississippi PSC. See Note (G) toPSC (and any subsequent related legal challenges), the Condensed Financial Statements under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" 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 now be determined at this time, but could result in further material charges that could have a material impact on Mississippi Power'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
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based upon assumptionsAs of March 31, 2017, in addition to the $2.87 billion of costs above the Mississippi Power's petitionPSC's $2.88 billion cost cap that have been recognized as a charge to income, Mississippi Power had incurred approximately $2.01 billion in costs subject to the cost cap and approximately $1.50 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following:
|
| | | |
| Cost Category | Actual Costs |
| | (in billions) |
| Gasifiers and Gas Clean-up Facilities | $ | 1.90 |
|
| Lignite Mine Facility | 0.31 |
|
CO2 Pipeline Facilities | 0.11 |
|
| Combined Cycle and Common Facilities | 0.17 |
|
| AFUDC | 0.73 |
|
| General exceptions | 0.07 |
|
| Plant inventory | 0.04 |
|
| Lignite inventory | 0.06 |
|
| Regulatory and other deferred assets | 0.12 |
|
| Subtotal | 3.51 |
|
| Additional DOE Grants | (0.14 | ) |
| Total | $ | 3.37 |
|
Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. Mississippi Power and its wholesale customers have generally agreed to similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the CPCN.first five years after the Kemper IGCC is placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period. Mississippi Power will not seek recovery of the $68 million in additional estimated costs from customers if incurred.
Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to apply operational parametersaddress these matters in connection with future proceedings related to the operation2017 Rate Case.
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Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected.
As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. ToThe project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC determinesto address this matter in connection with the 2017 Rate Case.
2017 Rate Case
Mississippi Power continues to believe that all costs related to the Kemper IGCC doesthat remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under "Prudence," "Lignite Mine and CO2 Pipeline Facilities," "Termination of Proposed Sale of Undivided Interest," and "Income Tax Matters," these challenges include, but are not meetlimited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the operational parameters ultimately adopted by15% portion of the project previously contracted to SMEPA.
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 utilize this legislation 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.
After the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. In connection with the 2017 Rate Case, Mississippi Power expects to file a request for authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event the Mississippi PSC does not grant Mississippi Power's request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power incurs additionalis developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to satisfybe filed by June 3, 2017. Mississippi
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such parameters, there could be a material adverse impactan agreement on Mississippi Power's financial statements.statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) 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. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. 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. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Prudence""Termination of Proposed Sale of Undivided Interest" herein for additional information. Mississippi Power is required to file the 2017 Rate Case by June 3, 2017.
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
2013 MPSC Rate Order
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, based on a mirror CWIP methodology (Mirror CWIP rate).
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. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.above.
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) 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. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. 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. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
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 regardingBecause the 2013 MPSC Rate Order did not impactprovide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through March 31, 2017, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $445 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's ability to utilize alternaterecovery of financing through securitization orcosts during the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudencecourse of construction of the Kemper IGCC. On October 3, 2016,IGCC and Mississippi Power made a required compliance filing, which included a review and explanationPower's recovery of differences betweencosts following the date the Kemper IGCC project estimate set forthis placed in service. With respect to recovery of costs following the 2010 CPCN proceeding andin-service date of the most recent Kemper IGCC, project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 20102012 MPSC CPCN proceedingsOrder provided for the first five years following the startestablishment of commercial operations. Certain costs,operational cost and revenue parameters including operationsavailability factor, heat rate, lignite heat content, and maintenance, are materially higher than the amounts presentedchemical revenue based upon assumptions in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up periodMississippi Power's petition for the current estimates reflects a lower starting point and a slower escalation rate.CPCN. Mississippi Power expects the Mississippi PSC to address these issuesapply operational parameters in connection with its next rate request.the 2017 Rate Case and 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 be a material adverse impact on Mississippi Power's financial statements. See "Prudence" herein for additional information.
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, 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 amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2016,March 31, 2017, the balance associated with these regulatory assets was $105$86 million, of which $33$24 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105$111 million as of September 30, 2016.March 31, 2017. The amortization period for 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.2017 Rate Case. See "FERC Matters""FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
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. At September 30, 2016,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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March 31, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7$8 million. See "2015 Rate Case" herein for additional information.
See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
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 IGCC 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 operating and managing the mining operations. The contract with Liberty Fuels is effective 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. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and 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 or otherwise sequester the CO2 produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally 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 cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. 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 July 31, 2018.
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. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi, where the case is currently pending. However, theMississippi. The plaintiffs have filed a request to remand the case back to state court.court, which was granted on
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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November 17, 2016. The individual plaintiff, John Carlton Dean, 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 IGCC 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 IGCC; 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 IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and Mississippi Power filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.
On June 9, 2016, Treetop, 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 relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court is expected to address in the second quarter 2017.
Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.
Bonus Depreciation
The extension of 50%information on bonus depreciation, included ininvestment tax credits, and the PATH Act is expected to result in approximately $400 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016, of which $250 million has been received as of September 30, 2016 through quarterly income tax refunds. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle"Section 174 research and Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.experimental deduction.
Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power'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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Electric Utility Regulation, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and AFUDC.Contingent Obligations.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2016,2017, 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 Initial 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 Initial DOE Grants and excluding the Cost Cap Exceptions.
As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC subject to the construction cost cap of $108 million ($67 million after tax) in the first quarter 2017, $127 million ($78 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, $53 million ($33 million after tax) in the first quarter 2016, $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, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2012. In the aggregate, Mississippi Power has incurred charges of $2.63$2.87 billion ($1.631.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.March 31, 2017.
Mississippi Power's revised cost estimate reflects an expected in-service date of DecemberMay 31, 20162017 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
In addition duringto the start-up and commissioning process,current construction cost estimate, Mississippi Power is also identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. TheApproximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimates,estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.
Any extension of the in-service date beyond December 31, 2016the end of May 2017 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 tobeyond the Kemper IGCC beyond December 31, 2016end of May 2017 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 $15$16 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 $3 million per month.
Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further in Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Prudence," " – Lignite Mine and CO2 Pipeline Facilities," " – Termination of Proposed Sale of Undivided Interest," and " – Income Tax Matters" herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.
Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Mississippi Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Mississippi Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Mississippi Power has not elected its transition method.
On February 25, 2016,March 10, 2017, the FASB issued ASU No. 2016-02,2017-07, Leases(Topic 842)Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2016-02)2017-07). ASU 2016-022017-07 requires lessees to recognize onthat an employer report the balance sheet a lease liabilityservice cost component in the same line item or items as other compensation costs and a right-of-use asset for all leases. ASU 2016-02 also changesrequires the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certainother 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, with early adoption permitted. Mississippi Power is currently evaluating the new standardnet periodic pension and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expectedpostretirement benefit costs to have a significant impact on Mississippi Power's balance sheet.
On March 30, 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. Most significantly, 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 benefitbe separately presented in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related tostatement outside income from operations. Additionally, only the exercise and vestingservice 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 stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15,the
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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2016. Early adoptionservice cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of 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 permitted andeffective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Mississippi Power intendsis currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to adopt theresult in a decrease in operating income and an increase in other income for 2018. The adoption of ASU in the fourth quarter 2016. The adoption2017-07 is not expected to have a material impact on the results of operations,Mississippi Power's financial position, or cash flows of Mississippi Power.statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the ninethree months ended September 30, 2016March 31, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.
Through September 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.
Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2021.2022. In addition to the Kemper IGCC, 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.
On JanuaryFebruary 28, 2016, Mississippi Power issued a2017, the maturity dates for $551 million in promissory note for up to $275 millionnotes to Southern Company which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issuedwere extended to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015.July 31, 2018. As of September 30, 2016,March 31, 2017, the amount of outstanding promissory notes to Southern Company totaled $551 million.
As of September 30, 2016,March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $411 million$1.2 billion primarily due to the $300a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes which maturedthat mature on OctoberNovember 15, 2016,2017, as well as $65$36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017, Mississippi Power borrowed an additional $10 million under a promissory note to Southern Company, which was amended and restated in short-term debt.
February 2017. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well assatisfy these obligations through loans and, under certain circumstances,and/or equity contributions from Southern Company. Specifically, 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 contributions sufficient to fund the remainderremaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of its short-term capital needs. See "Capital RequirementsMississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and Contractual Obligations,6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," "Sourcesrespectively, in Item 8 of Capital,"the Form 10-K and "Financing Activities" herein for additional information.Note (E) to the Condensed Financial Statements under "Going Concern" herein.
Net cash provided fromused for operating activities totaled $372$40 million for the first ninethree months of 2016,2017, an increase of $23$17 million as compared to the corresponding period in 2015.2016. The increase in cash provided fromused for operating activities is primarily due to lower income taxes receivable associated with researchtax benefits related to the Kemper IGCC and experimental (R&E) deductions and accrued taxes,current assets, primarily due to receivables, partially offset by lower R&E tax deductions, the cessationcompletion of Mirror CWIP collections and subsequent refund payments, and higher recovery of regulatory fuel clause revenues.refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $509$190 million for the first ninethree months of 20162017 primarily due to gross property additions related to the Kemper IGCC, partially offset by receipt of $137 million in Additional DOE Grants.IGCC. Net cash provided from financing activities totaled $198$12 million for the first ninethree months of 2017 primarily due to an increase in notes
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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of 2016 primarily due to long-term debt issuancespayable and capital contributions from Southern Company, partially offset by redemptions of long-term debt and a decrease in short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include a $218 million decrease in cash and cash equivalents and an increase in current liabilities and a decrease in long-term debt of $826 million. A portion of thisprimarily resulting from the $1.2 billion unsecured term loan agreement being reclassified from long-term debt was used to repay securities and notes payable resulting in a $385 million decrease in securities due within one yearyear. These changes are partially offset by $551 million of promissory notes to Southern Company being reclassified from current to long-term debt as a result of the maturity dates being extended to July 31, 2018 and a $475 million decreasean increase in notes payable. Additionally, CWIP increased $271total property, plant, and equipment of $109 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million.IGCC. Other significant changes include a $110 million increasedecrease in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes (ADIT) due to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the estimated losses on the Kemper IGCC construction, and a $39 million increase in prepaid income taxes. Total common stockholder's equity increased $269of $48 million primarily due to the receipt of capital contributions from Southern Company and net income for the period.ad valorem tax payments.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $300 million$1.2 billion will be required through September 30, 2017March 31, 2018 to fund maturities of long-term debt and $25$36 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $0.8 billion for 2016, net of the Additional DOE Grants, $0.3 billion$659 million for 2017, $0.2 billion$241 million for 2018, $0.2 billion$274 million for 2019, $0.3 billion$305 million for 2020, and $0.3 billion$230 million for 2021, and $289 million for 2022, which includes revised estimates forcompletion of the Kemper IGCC includingand post-in-service costs. The expendituresExpenditures related to the construction and start-upcompletion of the Kemper IGCC are currently estimated to be $0.7 billion for 2016, net of the Additional DOE Grants, and $0.1 billion$395 million for 2017. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approvedfuture state plans that would limit CO2 emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.
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 statutes 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 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, the construction program includes the development and construction of the Kemper IGCC, a 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 and construction 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, sustaining nitrogen supply, 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 Mississippi PSC).
See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
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Sources of Capital
In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Costs" of Mississippi Power in Item 7 of the Form 10-K for additional information.
On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. As of March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $1.2 billion primarily due to a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes that mature on November 15, 2017, as well as $36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017, Mississippi Power borrowed an additional $10 million under a promissory note to Southern Company. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, 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 contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.
Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. OnIn April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, seeSee Note 3(B) to the financial statements of Mississippi PowerCondensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-KCycle – Baseload Act" herein for additional information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million pursuant to the $275 million promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
Mississippi Power 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 Mississippi Power's short-term capital needs.
At September 30, 2016,March 31, 2017, Mississippi Power had approximately $159$6 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016March 31, 2017 were as follows:
| | | Expires | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Expires Within One Year |
| 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2017 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) |
| $ | 100 |
| | $ | 75 |
| | $ | 175 |
| | $ | 150 |
| | $ | — |
| | $ | 15 |
| | $ | 15 |
| | $ | 160 |
| 173 |
| | $ | 173 |
| | $ | 141 |
| | $ | — |
| | $ | 13 |
| | $ | 13 |
| | $ | 160 |
|
See Note 6 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as Mississippi Power's term loan arrangements,agreement, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(including (including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017,
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Mississippi Power 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, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $150$141 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds and commercial paper borrowings.bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016March 31, 2017 was approximately $40 million. In addition, at March 31, 2017, Mississippi Power had approximately $50 million of fixed rate pollution control bonds outstanding that were required to be remarketed within the next 12 months.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at September 30, 2016 | | 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) |
| Short-term bank debt | | $ | 25 |
| | 2.2% | | $ | 25 |
| | 2.1% | | $ | 25 |
|
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at March 31, 2017 | | 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) |
| Short-term bank debt | | $ | 36 |
| | 3.4% | | $ | 25 |
| | 2.7% | | $ | 36 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.March 31, 2017. |
Credit Rating Risk
At March 31, 2017, Mississippi Power 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 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 September 30, 2016,March 31, 2017, the maximum 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 $259$233 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 Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.
On May 12, 2016, FitchMarch 1, 2017, Moody's downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+Ba1 from A-Baa3.
On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and revisedits subsidiaries (including Mississippi Power) from stable to negative.
On March 30, 2017, Fitch placed the ratings outlook from negative to stable.of Mississippi Power on rating watch negative.
Financing Activities
On JanuaryFebruary 28, 2016,2017, Mississippi Power issued aamended $551 million in promissory note for up to $275 millionnotes to Southern Company which matures inextending the maturity dates of the notes from December 1, 2017 bearing interest based on one-month LIBOR. During the first nine months of 2016,to July 31, 2018. Subsequent to March 31, 2017, Mississippi Power borrowed $100an additional $10 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount ofCompany.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
$1.2 billion.On March 31, 2017, Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power receivedissued a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
In June 2016, Mississippi Power renewed a $10$9 million short-term note which matures on June 30, 2017, bearing interest basedat 5% per annum, which was repaid on three-month LIBOR.
In September 2016, Mississippi Power entered into interest rate swaps to fix the variable interest rate on $900 million of the term loan entered into in March 2016.April 27, 2017.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Operating Revenues: | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 387 |
| | $ | 295 |
| | $ | 866 |
| | $ | 776 |
| $ | 347 |
| | $ | 215 |
|
| Wholesale revenues, affiliates | 110 |
| | 104 |
| | 313 |
| | 303 |
| 100 |
| | 97 |
|
| Other revenues | 3 |
| | 2 |
| | 10 |
| | 7 |
| 3 |
| | 3 |
|
| Total operating revenues | 500 |
| | 401 |
| | 1,189 |
| | 1,086 |
| 450 |
| | 315 |
|
| Operating Expenses: | | | | | | | | | | |
| Fuel | 154 |
| | 118 |
| | 341 |
| | 361 |
| 132 |
| | 91 |
|
| Purchased power, non-affiliates | 25 |
| | 17 |
| | 60 |
| | 52 |
| 25 |
| | 13 |
|
| Purchased power, affiliates | 8 |
| | 5 |
| | 16 |
| | 18 |
| 5 |
| | 6 |
|
| Other operations and maintenance | 81 |
| | 62 |
| | 246 |
| | 184 |
| 92 |
| | 79 |
|
| Depreciation and amortization | 93 |
| | 64 |
| | 247 |
| | 183 |
| 119 |
| | 73 |
|
| Taxes other than income taxes | 5 |
| | 6 |
| | 17 |
| | 17 |
| 12 |
| | 6 |
|
| Total operating expenses | 366 |
|
| 272 |
| | 927 |
| | 815 |
| 385 |
| | 268 |
|
| Operating Income | 134 |
| | 129 |
| | 262 |
| | 271 |
| 65 |
| | 47 |
|
| Other Income and (Expense): | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (35 | ) | | (18 | ) | | (78 | ) | | (62 | ) | (50 | ) | | (21 | ) |
| Other income (expense), net | 2 |
| | 1 |
| | 3 |
| | 1 |
| (1 | ) | | 2 |
|
| Total other income and (expense) | (33 | ) | | (17 | ) | | (75 | ) | | (61 | ) | (51 | ) | | (19 | ) |
| Earnings Before Income Taxes | 101 |
| | 112 |
| | 187 |
| | 210 |
| 14 |
| | 28 |
|
| Income taxes (benefit) | (102 | ) | | 1 |
| | (167 | ) | | 14 |
| (52 | ) | | (23 | ) |
| Net Income | 203 |
| | 111 |
| | 354 |
| | 196 |
| 66 |
| | 51 |
|
| Less: Net income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
| |
| Less: Net income (loss) attributable to noncontrolling interests | | (4 | ) | | 1 |
|
| Net Income Attributable to Southern Power | $ | 176 |
| | $ | 102 |
| | $ | 315 |
| | $ | 181 |
| $ | 70 |
| | $ | 50 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | For the Three Months Ended March 31, |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) |
| Net Income | $ | 203 |
| | $ | 111 |
| | $ | 354 |
| | $ | 196 |
| $ | 66 |
| | $ | 51 |
|
| Other comprehensive income (loss): | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | |
| Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively | 23 |
| | — |
| | (1 | ) | | — |
| |
Reclassification adjustment for amounts included in net
income, net of tax of $(1), $-, $7, and $-, respectively | (1 | ) | | — |
| | 13 |
| | — |
| |
| Changes in fair value, net of tax of $(4) and $-, respectively | | (8 | ) | | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $(3) and $-, respectively | | (4 | ) | | 1 |
|
| Total other comprehensive income (loss) | 22 |
| | — |
| | 12 |
| | — |
| (12 | ) | | 1 |
|
| Less: Comprehensive income attributable to noncontrolling interests | 27 |
| | 9 |
| | 39 |
| | 15 |
| |
| Less: Comprehensive income (loss) attributable to noncontrolling interests | | (4 | ) | | 1 |
|
| Comprehensive Income Attributable to Southern Power | $ | 198 |
| | $ | 102 |
| | $ | 327 |
| | $ | 181 |
| $ | 58 |
| | $ | 51 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Three Months Ended March 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 66 |
| | $ | 51 |
|
| Adjustments to reconcile net income to net cash provided from (used for) operating activities — | | | |
| Depreciation and amortization, total | 127 |
| | 75 |
|
| Deferred income taxes | 36 |
| | (132 | ) |
| Amortization of investment tax credits | (14 | ) | | (7 | ) |
| Deferred revenues | (27 | ) | | (26 | ) |
| Other, net | 5 |
| | 9 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (7 | ) | | (3 | ) |
| -Prepaid income taxes | (21 | ) | | (31 | ) |
| -Other current assets | (6 | ) | | 1 |
|
| -Accounts payable | (38 | ) | | (12 | ) |
| -Accrued taxes | (40 | ) | | (37 | ) |
| -Other current liabilities | 15 |
| | 2 |
|
| Net cash provided from (used for) operating activities | 96 |
| | (110 | ) |
| Investing Activities: | | | |
| Business acquisitions | (1,020 | ) | | (114 | ) |
| Property additions | (69 | ) | | (767 | ) |
| Change in construction payables | (125 | ) | | 31 |
|
| Payments pursuant to LTSAs | (31 | ) | | (25 | ) |
| Investment in restricted cash | (13 | ) | | (289 | ) |
| Distribution of restricted cash | 26 |
| | 292 |
|
| Other investing activities | (3 | ) | | (1 | ) |
| Net cash used for investing activities | (1,235 | ) | | (873 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 171 |
| | 276 |
|
| Distributions to noncontrolling interests | (18 | ) | | (4 | ) |
| Capital contributions from noncontrolling interests | 71 |
| | 131 |
|
| Purchase of membership interests from noncontrolling interests | — |
| | (129 | ) |
| Payment of common stock dividends | (79 | ) | | (68 | ) |
| Other financing activities | (12 | ) | | — |
|
| Net cash provided from financing activities | 133 |
| | 206 |
|
| Net Change in Cash and Cash Equivalents | (1,006 | ) | | (777 | ) |
| Cash and Cash Equivalents at Beginning of Period | 1,099 |
| | 830 |
|
| Cash and Cash Equivalents at End of Period | $ | 93 |
| | $ | 53 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $2 and $10 capitalized for 2017 and 2016, respectively) | $ | 28 |
| | $ | 15 |
|
| Income taxes, net | (1 | ) | | 188 |
|
| Noncash transactions — Accrued property additions at end of period | 53 |
| | 262 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 93 |
| | $ | 1,099 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 111 |
| | 102 |
|
| Other accounts receivable | | 32 |
| | 34 |
|
| Affiliated | | 62 |
| | 57 |
|
| Fossil fuel stock | | 14 |
| | 15 |
|
| Materials and supplies | | 343 |
| | 337 |
|
| Prepaid income taxes | | 95 |
| | 74 |
|
| Other current assets | | 31 |
| | 39 |
|
| Total current assets | | 781 |
| | 1,757 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 13,493 |
| | 12,728 |
|
| Less: Accumulated provision for depreciation | | 1,598 |
| | 1,484 |
|
| Plant in service, net of depreciation | | 11,895 |
| | 11,244 |
|
| Construction work in progress | | 328 |
| | 398 |
|
| Total property, plant, and equipment | | 12,223 |
| | 11,642 |
|
| Other Property and Investments: | | | | |
Intangible assets, net of amortization of $28 and $22
at March 31, 2017 and December 31, 2016, respectively | | 430 |
| | 436 |
|
| Total other property and investments | | 430 |
| | 436 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid LTSAs | | 120 |
| | 101 |
|
| Accumulated deferred income taxes | | 570 |
| | 594 |
|
| Other deferred charges and assets — affiliated | | 26 |
| | 13 |
|
| Other deferred charges and assets — non-affiliated | | 531 |
| | 626 |
|
| Total deferred charges and other assets | | 1,247 |
| | 1,334 |
|
| Total Assets | | $ | 14,681 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 560 |
| | $ | 560 |
|
| Notes payable | | 380 |
| | 209 |
|
| Accounts payable — | | | | |
| Affiliated | | 76 |
| | 88 |
|
| Other | | 129 |
| | 278 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 48 |
| | 148 |
|
| Other accrued taxes | | 13 |
| | 7 |
|
| Accrued interest | | 47 |
| | 36 |
|
| Acquisitions payable | | — |
| | 461 |
|
| Contingent consideration | | 14 |
| | 46 |
|
| Other current liabilities | | 69 |
| | 70 |
|
| Total current liabilities | | 1,336 |
| | 1,903 |
|
| Long-term Debt | | 5,088 |
| | 5,068 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 157 |
| | 152 |
|
| Accumulated deferred investment tax credits | | 1,879 |
| | 1,839 |
|
| Asset retirement obligations | | 67 |
| | 64 |
|
| Other deferred credits and liabilities | | 288 |
| | 304 |
|
| Total deferred credits and other liabilities | | 2,391 |
| | 2,359 |
|
| Total Liabilities | | 8,815 |
| | 9,330 |
|
| Redeemable Noncontrolling Interests | | 164 |
| | 164 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 3,671 |
| | 3,671 |
|
| Retained earnings | | 714 |
| | 724 |
|
| Accumulated other comprehensive income | | 24 |
| | 35 |
|
| Total common stockholder's equity | | 4,409 |
| | 4,430 |
|
| Noncontrolling interests | | 1,293 |
| | 1,245 |
|
| Total stockholders' equity | | 5,702 |
| | 5,675 |
|
| Total Liabilities and Stockholders' Equity | | $ | 14,681 |
| | $ | 15,169 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 354 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 262 |
| | 187 |
|
| Deferred income taxes | (668 | ) | | 222 |
|
| Investment tax credits | — |
| | 294 |
|
| Amortization of investment tax credits | (25 | ) | | (14 | ) |
| Deferred revenues | 9 |
| | 15 |
|
| Collateral deposits | (80 | ) | | — |
|
| Accrued income taxes, non-current | — |
| | 100 |
|
| Other, net | 10 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (82 | ) | | (28 | ) |
| -Prepaid income taxes | (16 | ) | | (116 | ) |
| -Other current assets | 1 |
| | 1 |
|
| -Accounts payable | 7 |
| | 1 |
|
| -Accrued taxes | 483 |
| | (247 | ) |
| -Other current liabilities | 14 |
| | (12 | ) |
| Net cash provided from operating activities | 269 |
| | 609 |
|
| Investing Activities: | | | |
| Business acquisitions | (1,134 | ) | | (1,128 | ) |
| Property additions | (1,702 | ) | | (348 | ) |
| Change in construction payables | (69 | ) | | 88 |
|
| Payments pursuant to long-term service agreements | (58 | ) | | (65 | ) |
| Investment in restricted cash | (750 | ) | | — |
|
| Distribution of restricted cash | 746 |
| | — |
|
| Other investing activities | (41 | ) | | (1 | ) |
| Net cash used for investing activities | (3,008 | ) | | (1,454 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 692 |
| | 18 |
|
| Proceeds — | | | |
| Senior notes | 1,531 |
| | 650 |
|
| Capital contributions | 800 |
| | 226 |
|
| Other long-term debt | 63 |
| | 400 |
|
| Redemptions — | | | |
| Senior notes | — |
| | (525 | ) |
| Other long-term debt | (84 | ) | | (3 | ) |
| Distributions to noncontrolling interests | (22 | ) | | (6 | ) |
| Capital contributions from noncontrolling interests | 367 |
| | 274 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
|
| Payment of common stock dividends | (204 | ) | | (98 | ) |
| Other financing activities | (14 | ) | | (5 | ) |
| Net cash provided from financing activities | 3,000 |
| | 931 |
|
| Net Change in Cash and Cash Equivalents | 261 |
| | 86 |
|
| Cash and Cash Equivalents at Beginning of Period | 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,091 |
| | $ | 161 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively) | $ | 49 |
| | $ | 69 |
|
| Income taxes, net | 71 |
| | (215 | ) |
| Noncash transactions — Accrued property additions at end of period | 210 |
| | 120 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,091 |
| | $ | 830 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 121 |
| | 75 |
|
| Other accounts receivable | | 25 |
| | 19 |
|
| Affiliated | | 67 |
| | 30 |
|
| Fossil fuel stock | | 14 |
| | 16 |
|
| Materials and supplies | | 163 |
| | 63 |
|
| Prepaid income taxes | | 61 |
| | 45 |
|
| Other current assets | | 32 |
| | 30 |
|
| Total current assets | | 1,574 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 9,491 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,465 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 8,026 |
| | 6,027 |
|
| Construction work in progress | | 1,652 |
| | 1,137 |
|
| Total property, plant, and equipment | | 9,678 |
| | 7,164 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $16 and $12
at September 30, 2016 and December 31, 2015, respectively | | 389 |
| | 317 |
|
| Total other property and investments | | 391 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | |
| Prepaid long-term service agreements | | 151 |
| | 166 |
|
| Accumulated deferred income taxes | | 199 |
| | — |
|
| Other deferred charges and assets — affiliated | | 3 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 355 |
| | 139 |
|
| Total deferred charges and other assets | | 708 |
| | 314 |
|
| Total Assets | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At September 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 60 |
| | $ | 403 |
|
| Notes payable | | 828 |
| | 137 |
|
| Accounts payable — | | | | |
| Affiliated | | 91 |
| | 66 |
|
| Other | | 218 |
| | 327 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 147 |
| | 198 |
|
| Other accrued taxes | | 16 |
| | 5 |
|
| Accrued interest | | 30 |
| | 23 |
|
| Contingent consideration | | 30 |
| | 36 |
|
| Other current liabilities | | 97 |
| | 44 |
|
| Total current liabilities | | 1,517 |
| | 1,239 |
|
| Long-term Debt | | 4,548 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 140 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 1,385 |
| | 889 |
|
| Accrued income taxes, non-current | | 109 |
| | 109 |
|
| Asset retirement obligations | | 40 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 19 |
| | 17 |
|
| Other deferred credits and liabilities | | 115 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,808 |
| | 1,640 |
|
| Total Liabilities | | 7,873 |
| | 5,598 |
|
| Redeemable Noncontrolling Interests | | 49 |
| | 43 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $.01 per share — | | | | |
| Authorized — 1,000,000 shares | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
|
| Paid-in capital | | 2,620 |
| | 1,822 |
|
| Retained earnings | | 769 |
| | 657 |
|
| Accumulated other comprehensive income (loss) | | 16 |
| | 4 |
|
| Total common stockholder's equity | | 3,405 |
| | 2,483 |
|
| Noncontrolling interests | | 1,024 |
| | 781 |
|
| Total stockholders' equity | | 4,429 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 12,351 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THIRDFIRST QUARTER 20162017 vs. THIRDFIRST QUARTER 2015
AND
YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015
OVERVIEW
Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates 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, construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
During the ninethree months ended September 30, 2016,March 31, 2017, Southern Power acquired or commencedcompleted the construction of, and placed in service, approximately 396 MWs of solar and wind facilities. In addition, Southern Power continued the construction of approximately 758447 MWs of additional solar and windnatural gas facilities, and,of which 102 MWs from a solar facility were placed in service subsequent to September 30, 2016, acquired or commenced construction of approximately 977 MWs of wind and natural gas facilities. In addition, Southern Power has committed to acquire approximately 674 MWs of solar and wind facilities over the next several months.March 31, 2017. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
At September 30, 2016,March 31, 2017, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% through 2025,2021 and 90% through 2026, with an average remaining contract duration of approximately 1716 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.
Southern Power continues to focus on several key performance indicators. These indicators, includeincluding, but not limited to, peak season equivalent forced outage rate, contract availability, and net income. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $74 | | 72.5 | | $134 | | 74.0 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $20 | | 40.0 |
Net income attributable to Southern Power for the thirdfirst quarter 20162017 was $176$70 million compared to $102$50 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 20162016. The increase was $315 million compared to $181 million for the corresponding period in 2015. The increases were primarily due to increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and interest expense from debt issuances, allprimarily related to Southern Power's new solar and windgenerating facilities.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Revenues
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $99 | | 24.7 | | $103 | | 9.5 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $135 | | 42.9 |
OperatingTotal 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, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has unused capacity not contracted under a PPA, it may sell power into the wholesale market ormarket. To the extent Southern Power (excluding its subsidiaries) has capacity not contracted under a PPA, it may sell power into the power pool.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to net income and are an integral componentdesigned to provide recovery of Southern Power's natural gas and biomass PPAs. fixed costs plus a return on investment.
Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. 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
Southern Power's electricity sales from solar and wind generating facilities are alsopredominantly through long-term PPAs; however, these solar and wind PPAs that do not have a capacity charge and customerscharge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge.charge or pay a fixed price for 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, and other factors.
See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.
Details of Southern Power's operating revenues were as follows:
| | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | First Quarter 2017 | | First Quarter 2016 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) | (in millions) |
| PPA capacity revenues | $ | (19 | ) | | (11.8) | | $ | (25 | ) | | (5.8) | $ | 148 |
| | $ | 124 |
|
| PPA energy revenues | 62 |
| | 33.3 | | 79 |
| | 17.5 | 198 |
| | 117 |
|
| Total PPA revenues | 43 |
| | 11.8 | | 54 |
| | 6.1 | 346 |
| | 241 |
|
| Revenues not covered by PPAs | 55 |
| | 121.9 | | 46 |
| | 23.4 | |
| Non-PPA revenues | | 101 |
| | 71 |
|
| Other revenues | 1 |
| | 50.0 | | 3 |
| | 42.9 | 3 |
| | 3 |
|
| Total operating revenues | $ | 99 |
| | 24.7% | | $ | 103 |
| | 9.5% | $ | 450 |
| | $ | 315 |
|
In the thirdfirst quarter 2016,2017, total operating revenues were $500$450 million, compared to $401reflecting a $135 million, foror 43%, increase from the corresponding period in 2015.2016. The $99 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $19increased $24 million, or 19%, primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.new PPAs related to natural gas facilities and additional customer load requirements.
PPA energy revenuesincreased $62$81 million, primarily due to an increase in renewable energy sales from new solar and wind facilities.
Revenues not covered by PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs.
For year-to-date 2016, operating revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2015. The $103 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.
PPA energy revenuesincreased $79 million primarilyor 69%, due to a $122$60 million increase in renewable energy sales arisingprimarily from new solar and wind facilities partially offset byand a decrease of $43$21 million increase in fuel revenues related toenergy sales primarily from new natural gas facility PPAs. Overall, total KWH sales under PPAs increased 32% in the first quarter 2017 when compared to the corresponding period in 2016.
Non-PPA revenues increased $30 million, or 42%, primarily due to a 62% increase in short-term KWH sales to the wholesale market from Southern Power's natural gas facilities.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.
Wholesale revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power'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.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market and the power pool.market. Details of Southern Power's generation and purchased power were as follows:
| | | | Third Quarter 2016 | Third Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 | First Quarter 2017 | First Quarter 2016 |
| | (in billions of KWHs) | (in billions of KWHs) |
| Generation | 11.1 | 9.4 | | 27.9 | 24.8 | 9.7 | 7.7 |
| Purchased power | 0.9 | 0.5 | | 2.5 | 1.5 | 0.9 | 0.6 |
| Total generation and purchased power | 12.0 | 9.9 | | 30.4 | 26.3 | 10.6 | 8.3 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 6.7 | 5.2 | | 17.7 | 15.9 | 4.9 | 5.3 |
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power 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 Southern Power (excluding its subsidiaries).Power.
Purchased power expenses will vary depending on demand, availability, and the 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 Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | | | Third Quarter 2016
vs.
Third Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 | | First Quarter 2017
vs.
First Quarter 2016 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | 36 |
| | 30.5 | | $ | (20 | ) | | (5.5) | | $ | 41 |
| | 45.1 |
| Purchased power | | 11 |
| | 50.0 | | 6 |
| | 8.6 | | 11 |
| | 57.9 |
| Total fuel and purchased power expenses | | $ | 47 |
| | $ | (14 | ) | | | $ | 52 |
| |
In the thirdfirst quarter 2016,2017, total fuel and purchased power expenses were $187increased $52 million, or 47%, compared to $140 million for the corresponding period in 2015. The increase was primarily due to the following:
2016. Fuel expense increased $36$41 million primarily due to a $27$54 million increase associated within the volume of KWHs generated and a $9 million increase associated with average cost of natural gas per KWH generated, partially offset by a $13 million decrease in the volume of KWHs generated. Purchased power expense increased $11 million due to a $9 million increase in the volume of KWHs purchased and a $2 million increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $13 | | 16.5 |
In the first quarter 2017, other operations and maintenance expenses were $92 million compared to $79 million for the corresponding period in 2016. The increase was primarily due to a $16 million increase associated with new
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased power expense increased $11 million due tosolar, wind, and gas facilities and a $19$4 million increase associated with the volumeemployee compensation and expenses in support of KWHs purchased,Southern Power's overall growth strategy, partially offset by a $4$7 million decrease in scheduled outage and maintenance expenses.
Depreciation and Amortization
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $46 | | 63.0 |
In the average cost of purchased powerfirst quarter 2017, depreciation and a $4 million decrease associated with a PPA expiration.
For year-to-date 2016, total fuel and purchased power expenses were $417amortization was $119 million compared to $431$73 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.
Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $19 | | 30.6 | | $62 | | 33.7 |
In the third quarter 2016, other operations and maintenance expenses were $81 million compared to $62 million for the corresponding period in 2015.2016. The increase was primarily due to a $9 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase associated with scheduled outage and maintenance expenses, and a $3 million increase in general business expenses associated with Southern Power's overall growth strategy.
For year-to-date 2016, other operations and maintenance expenses were $246 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to a $24 million increase associated with scheduled outage and maintenance expenses, a $22 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $14 million increase in general business expenses associated with Southern Power's overall growth strategy.
Depreciation and Amortization
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $29 | | 45.3 | | $64 | | 35.0 |
In the third quarter 2016, depreciation and amortization was $93 million compared to $64 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $247 million compared to $183 million for the corresponding period in 2015. The increases were primarily due to additional depreciation related to new solar, wind, and windgas facilities placed in service in 2015 and 2016.service.
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 94.4 | | $16 | | 25.8 |
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $29 | | 138.1 |
In the thirdfirst quarter 2016,2017, interest expense, net of amounts capitalized was $35$50 million compared to $18$21 million for the corresponding period in 2015.2016. The increase was primarily due to an increase of $25$21 million in interest expense related to additional debt issued since the third quarter of 2015in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, partially offset byas well as an $8 million increasedecrease in capitalized interest associated with the construction of solar facilities which were placed in service.
Other Income (Expense), Net
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(3) | | (150.0) |
In the first quarter 2017, other income (expense), net was $(1) million compared to $2 million for the corresponding period in 2016. The change includes a $17 million currency loss arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars, fully offset by a $17 million gain on the foreign currency hedge that was reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes (Benefit)
|
| | |
| First Quarter 2017 vs. First Quarter 2016 |
| (change in millions) | | (% change) |
| $(29) | | 126.1 |
In the first quarter 2017, income tax benefit was $52 million compared to $23 million for the corresponding period in 2016. The change was primarily due to a $30 million increase in wind PTC benefits, a $9 million increase resulting from state apportionment rate changes, and a $4 million increase related to lower pre-tax earnings, partially offset by a $12 million decrease in ITC benefits. See Note (G) to the Condensed Financial Statements herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
with the construction of solar facilities.
For year-to-date 2016, interest expense, net of amounts capitalized was $78 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to an increase of $43 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, largely offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.
Income Taxes (Benefit)
|
| | | | | | |
| Third Quarter 2016 vs. Third Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(103) | | N/M | | $(181) | | N/M |
N/M - Not meaningful
In the third quarter 2016, income tax benefit was $(102) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $96 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $10 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $3 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
For year-to-date 2016, income tax benefit was $(167) million compared to an expense of $14 million for the corresponding period in 2015. The change was primarily due to a $171 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $17 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $7 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
See Note (G) to the Condensed Financial Statements herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities;facilities. Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact of federal ITCs and PTCs. on Southern Power's financial statements.
Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand 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, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At DecemberMarch 31, 2015,2017, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% through 2020 and 70% through 2025, with an average remaining contract duration of approximately 10 years.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Power believes an investment coverage ratio best identifies the value offor its generating assets, covered since it representsbased 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)construction) as the investment amount. At September 30, 2016, the average investment coverage ratioamount, was 92% through 2020 and 91% through 2025,2021 and 90% through 2026, with an average remaining contract duration of approximately 1716 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 years.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power'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 legislative or regulatory changes cannot be determined at this time.
Environmental Statutes and Regulations
AirWater Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – AirWater Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's Cross State Air Pollution Rule (CSAPR).final effluent guidelines rule.
On October 26, 2016,April 25, 2017, the EPA published a finalnotice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Texas and removing Florida and North Carolina from the CSAPR program. effect.
The ultimate impactoutcome of this rule will depend on the outcome of any legal challenges and implementation at the state level andmatter cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information.
On March 28, 2017, the President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. The ultimate outcome of this matter cannot be determined at this time.
Acquisitions
During 2016,the three months ended March 31, 2017, in accordance with itsSouthern Power's overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and(SRP), one of Southern Renewable Energy, Inc.,Power's wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below.Bethel wind facility. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual/Expected COD | PPA Contract Period |
| Acquisitions During the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | 20 | Imperial County, CA | 90 | % | | February 2016 | 20 years |
| East Pecos | Solar | 120 | Pecos County, TX | 100 | % | | December 2016 | 15 years |
| Grant Plains | Wind | 147 | Grant County, OK | 100 | % | | December 2016 | Up to 20 years |
| Grant Wind | Wind | 151 | Grant County, OK | 100 | % | | April 2016 | 20 years |
| Henrietta | Solar | 102 | Kings County, CA | 51 | % | (a) | July 2016 | 20 years |
| Lamesa | Solar | 102 | Dawson County, TX | 100 | % | | First quarter 2017 | 15 years |
| Passadumkeag | Wind | 42 | Penobscot County, ME | 100 | % | | July 2016 | 15 years |
| Rutherford | Solar | 74 | Rutherford County, NC | 90 | % | | December 2016 | 15 years |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | 375 | Mankato, MN | 100 | % | | N/A(b) | 10 years |
| Wake Wind | Wind | 257 | Floyd and Crosby Counties, TX | 90.1 | % | | 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) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million. Total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million for East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Acquisition Agreements Executed but Not Yet Closed
During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:
51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and
100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.
The ultimate outcome of these matters cannot be determined at this time. |
| | | | | | | | | |
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Percentage Ownership | Actual COD | PPA Counterparties | PPA Contract Period |
| Bethel | Wind | 276 | Castro County, TX | 100 | % | | January 2017 | Google Energy, LLC | 12 years |
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016Bethel facility included in the condensed consolidated statements of income for year-to-date 2016during the first quarter 2017 is $14$4 million. The aggregate amount of net income, excluding impacts of ITCs andfrom PTCs, attributable torecognized by Southern Power related to the project facilities acquired during the ninethree months ended September 30, 2016March 31, 2017 included in the condensed consolidated statements of income iswas immaterial. These businessesThe Bethel facility did not have operating revenues or activities prior to completion of construction and theirthe assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016, and for the comparable 20152016 period is not meaningful and has been omitted.
Construction Projects
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Construction Projects Completed and in Progress
During the ninethree months ended September 30, 2016,March 31, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016,March 31, 2017, total costs of construction incurred for the followingthese three projects were $3.0 billion,$401 million, of which $1.2 billion remains$203 million remained in CWIP. IncludingCWIP for the total construction costs incurred through September 30, 2016Lamesa and the acquisition prices allocated to CWIP, totalMankato facilities acquired in 2016. Total aggregate construction costs, forexcluding the following projectsacquisition costs, are estimatedexpected to be $3.1 billion$530 million to $3.2 billion.$590 million for these two facilities that were under construction at March 31, 2017. The ultimate outcome of these matters cannot be determined at this time.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | |
SolarProject Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties | PPA Contract Period |
ProjectsProject Completed During the NineThree Months Ended September 30, 2016March 31, 2017 |
Butler Solar FarmEast Pecos | 22Solar | Taylor120 | Pecos County, GATX | February 2016March 2017 | 20Austin Energy | 15 years |
Desert Stateline(a)
| 299(b)
| San Bernardino County, CA | Through July 2016 | 20 years |
Garland A | 20 | Kern County, CA | August 2016 | 20 years |
Pawpaw | 30 | Taylor County, GA | March 2016 | 30 years |
Tranquillity | 205 | Fresno County, CA | July 2016 | 18 years |
Projects Under Construction as of September 30, 2016March 31, 2017 |
ButlerLamesa | 103Solar | Taylor102 | Dawson County, GATX | December 2016April 2017 | 30 years |
| City of Garland, | 185 | Kern County, CA | October 2016 Texas | 15 years |
RoserockMankato | 160Natural Gas | Pecos County, TX345 | November 2016Mankato, MN | Second quarter 2019 | Northern States Power Company | 20 years |
Sandhills | 146 | Taylor County, GA | October 2016 | 25 years |
| |
(a) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are 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. |
| |
(b) | The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016. |
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
Income Tax Matters
Bonus Depreciation
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation"Matters" of Southern Power in Item 7 of the Form 10-K for additional information.
The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $650 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the NOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" and " – Tax Credit Carryforwards" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power'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 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 Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, orinNote3tothefinancialstatementsofSouthern PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power'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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
policies and estimates related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
Recently Issued Accounting Standards
On February 25, 2016,In 2014, the FASB issued ASU No. 2016-02, Leases(Topic 842)ASC 606, (ASU 2016-02). ASU 2016-02 requires lesseesRevenue from Contracts with Customers, 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 standard is to recognize onrevenue to depict the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02transfer of goods or services to customers at the amount expected to be collected. The new standard also changes the recognition, measurement, and presentation of expense associated with leases and provides clarificationrequires enhanced disclosures regarding the identificationnature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. Southern Power's ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer term contractual arrangements, such as certain componentscapacity payments under PPAs that are expected to be excluded from the scope of contracts that would represent a lease. ASC 606 and included in the scope of the current leasing guidance (ASC Topic 840).
The accounting required by lessors is relatively unchanged. ASU 2016-02new standard is effective for fiscal yearsinterim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.2017. Southern Power ismust select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently evaluatingdoes not expect the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact onto net income. Southern Power's balance sheet.Power has not elected a transition method as the ultimate impact of the new standard has not yet been determined.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at September 30, 2016.March 31, 2017. Southern Power 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 future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $269$96 million for the first ninethree months of 20162017 compared to $609net cash used for operating activities of $110 million for the first ninethree months of 2015.2016. The decreaseincrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCsrenewable energy sales arising from new solar and PTCs.wind facilities and a decrease in income taxes paid, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" hereinof Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $3.0$1.2 billion for the first ninethree months of 20162017 primarily due to payments for renewable acquisitions and the construction of renewable facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $3.0 billion$133 million for the first ninethree months of 20162017 primarily due to an increase in senior notes, notes payable and capital contributions from noncontrolling interests, partially offset by dividends to Southern Company.Company and distributions to noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first ninethree months of 20162017 include a $515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $2.2$1.0 billion increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $261 million increasedecrease in cash and cash equivalents and a $2.5 billion$765 million increase in notes payableproperty, plant, and long-term debtequipment in-service primarily related to acquisitions, as well as a $70 million decrease in CWIP primarily due to additional borrowings to fund acquisitions and constructionEast Pecos being placed in service, partially offset by equipment purchased for wind projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $60$560 million will be required to repay maturities of long-term debt through September 30, 2017. In addition, during the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements (LTSA), which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million.March 31, 2018.
Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures for Southern Power are currently estimated to total approximately $4.5 billion for 2016, primarily for acquisitions and/or construction of new generating facilities. Capital expenditures for Southern Power are currently estimated to total approximately $1.6 billion annually for 2017 through 2021. Actual capital 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 statutes 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 (I) to the Condensed Financial Statements herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. In 2017, Southern Power expects to utilize the debt capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.
As of September 30, 2016,March 31, 2017, Southern Power had cash and cash equivalents of approximately $1.1 billion.$93 million.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, and operating cash flows.
Southern Power'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. Southern Power's subsidiaries are not borrowers under the commercial paper program.
Details of short-term borrowingscommercial paper were as follows:
|
| | | | | | | | | | |
| | Short-term Debt During the Period (*) |
| | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | (in millions) | | | | (in millions) |
| Commercial paper | $ | 10 |
| | 0.9 | % | | $ | 62 |
|
|
| | | | | | | | | | | | | | | | |
| | Short-term Debt at March 31, 2017 | | 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) |
| Commercial paper | $ | 381 |
| 1.3 | % | | $ | 144 |
| | 1.1 | % | | $ | 381 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.March 31, 2017. |
Company Credit Facility
At September 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $68 million has been used for letters of credit and $532 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
TheCompany Credit Facility as well as
At March 31, 2017, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $76 million has been used for letters of credit and $524 million remains unused. Southern Power's term loan agreement, contains a covenant that limitssubsidiaries are not borrowers under 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 Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power 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 Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Facility, as well as Southern Power's commercial paper programterm loan agreement, 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 usedrestricted only to finance acquisitionindebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and construction costs relatedcapitalization excludes the capital stock or other equity attributable to electric generating facilities andsuch subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
In December 2016, Southern Power entered into an agreement for general corporate purposes, including maturing debt.a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At March 31, 2017, the total amount available under the facility was $67 million. Southern Power's subsidiaries are not borrowers underparties to the commercial paper program.facility.
Subsidiary Project Credit FacilitiesFacility
In connection with the construction of solar facilities byRE Garland Holdings LLC,the Roserock facility, RE Roserock LLC and RE Tranquillity LLC,, an indirect subsidiariessubsidiary of Southern Power, each subsidiary entered into separatea credit agreementsagreement (Project Credit Facilities)Facility), which arewas non-recourse to Southern Power (other than the subsidiary party to the agreement). EachThe 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,RE Roserock LLC, with proceeds directed to finance project costs related to the respective solar facilities. Eachfacility. The Project Credit Facility iswas secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. RE Roserock LLC.
The table below summarizes each Project Credit Facility as of was fully repaid on January 31, 2017.September 30, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
(*) | Subsequent to September 30, 2016, Roserock extended For the three-month period ended March 31, 2017, the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities aboveFacility had total amountsa maximum amount outstanding as of September 30, 2016$209 million and an average amount outstanding of $828$70 million at a weighted average interest rate of 2.05%2.1%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this 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 2.21%.
Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Southern Power 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, transmission, and foreign currency risk management.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The maximum potential collateral requirements under these contracts at September 30, 2016March 31, 2017 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and/or Baa2 | $ | 30 |
| $ | 38 |
|
| At BBB- and/or Baa3 | $ | 385 |
| $ | 409 |
|
| Below BBB- and/or Baa3 | $ | 1,104 |
| |
At BB+ and/or Ba1(*) | | $ | 1,188 |
|
| |
| (*) | 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 Southern Power to access capital markets and would be likely to impact the cost at which it does so.
In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power'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 Southern Power) from stable to negative.
Financing Activities
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of creditdid not issue or redeem any securities during the ninethree months ended September 30, 2016.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Subsequent to September 30, 2016, Southern Power's subsidiaries borrowed $5 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.03%. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.March 31, 2017.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power 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.
SOUTHERN COMPANY GAS
156AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended March 31, | | | For the Three Months Ended March 31, |
| | 2017 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Revenues: | | | | |
Natural gas revenues (includes revenue taxes of
$48 and $40 for the periods presented, respectively)
| $ | 1,530 |
| | | $ | 1,302 |
|
| Other revenues | 30 |
| | | 32 |
|
| Total operating revenues | 1,560 |
| | | 1,334 |
|
| Operating Expenses: | | | | |
| Cost of natural gas | 719 |
| | | 571 |
|
| Cost of other sales | 7 |
| | | 7 |
|
| Other operations and maintenance | 253 |
| | | 241 |
|
| Depreciation and amortization | 120 |
| | | 102 |
|
| Taxes other than income taxes | 70 |
| | | 62 |
|
| Merger-related expenses | — |
| | | 3 |
|
| Total operating expenses | 1,169 |
| | | 986 |
|
| Operating Income | 391 |
| | | 348 |
|
| Other Income and (Expense): | | | | |
| Earnings from equity method investments | 39 |
| | | 1 |
|
| Interest expense, net of amounts capitalized | (46 | ) | | | (48 | ) |
| Other income (expense), net | 5 |
| | | 3 |
|
| Total other income and (expense) | (2 | ) | | | (44 | ) |
| Earnings Before Income Taxes | 389 |
| | | 304 |
|
| Income taxes | 150 |
| | | 111 |
|
| Net Income | 239 |
| | | 193 |
|
| Less: Net income attributable to noncontrolling interest | — |
| | | 11 |
|
| Net Income Attributable to Southern Company Gas | $ | 239 |
| | | $ | 182 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended March 31, | | | For the Three Months Ended March 31, |
| | 2017 | | | 2016 |
| | (in millions) | | | (in millions) |
| Net Income | $ | 239 |
| | | $ | 193 |
|
| Other comprehensive income (loss): | | | | |
| Qualifying hedges: | | | | |
| Changes in fair value, net of tax of $(1) and $(16), respectively | (1 | ) | | | (29 | ) |
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively | — |
| | | (1 | ) |
| Pension and other postretirement benefit plans: | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $(1) and $2, respectively | (1 | ) | | | 3 |
|
| Total other comprehensive income (loss) | (2 | ) | | | (27 | ) |
| Less: Comprehensive income attributable to noncontrolling interest | — |
| | | 11 |
|
| Comprehensive Income Attributable to Southern Company Gas | $ | 237 |
| | | $ | 155 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | For the Three Months Ended March 31, | | | For the Three Months Ended March 31, |
| | 2017 | | | 2016 |
| | (in millions) | | | (in millions) |
| Operating Activities: | | | | |
| Net income | $ | 239 |
| | | $ | 193 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | |
| Depreciation and amortization, total | 120 |
| | | 102 |
|
| Deferred income taxes | 46 |
| | | 14 |
|
| Pension, postretirement, and other employee benefits | (6 | ) | | | 1 |
|
| Stock based compensation expense | 11 |
| | | 5 |
|
| Mark-to-market adjustments | (82 | ) | | | 5 |
|
| Other, net | 21 |
| | | (11 | ) |
| Changes in certain current assets and liabilities — | | | | |
| -Receivables | 117 |
| | | 34 |
|
| -Natural gas for sale, net of temporary LIFO liquidation | 411 |
| | | 363 |
|
| -Prepaid income taxes | 24 |
| | | 151 |
|
| -Other current assets | 19 |
| | | 27 |
|
| -Accounts payable | (216 | ) | | | (64 | ) |
| -Accrued taxes | 19 |
| | | 84 |
|
| -Accrued compensation | (14 | ) | | | (46 | ) |
| -Other current liabilities | 49 |
| | | (17 | ) |
| Net cash provided from operating activities | 758 |
| | | 841 |
|
| Investing Activities: | | | | |
| Property additions | (301 | ) | | | (222 | ) |
| Cost of removal, net of salvage | (11 | ) | | | (15 | ) |
| Change in construction payables, net | (12 | ) | | | 2 |
|
| Investment in unconsolidated subsidiaries | (81 | ) | | | (5 | ) |
| Other investing activities | — |
| | | 2 |
|
| Net cash used for investing activities | (405 | ) | | | (238 | ) |
| Financing Activities: | | | | |
| Decrease in notes payable, net | (234 | ) | | | (453 | ) |
| Redemptions and repurchases — First mortgage bonds | — |
| | | (75 | ) |
| Distributions to noncontrolling interest | — |
| | | (19 | ) |
| Payment of common stock dividends | (111 | ) | | | (64 | ) |
| Other financing activities | 1 |
| | | 9 |
|
| Net cash used for financing activities | (344 | ) | | | (602 | ) |
| Net Change in Cash and Cash Equivalents | 9 |
| | | 1 |
|
| Cash and Cash Equivalents at Beginning of Period | 19 |
| | | 19 |
|
| Cash and Cash Equivalents at End of Period | $ | 28 |
| | | $ | 20 |
|
| Supplemental Cash Flow Information: | | | | |
| Cash paid (received) during the period for — | | | | |
| Interest (net of $3 and $1 capitalized for 2017 and 2016, respectively) | $ | 41 |
| | | $ | 53 |
|
| Income taxes, net | — |
| | | (132 | ) |
| Noncash transactions — Accrued property additions at end of period | 53 |
| | | 51 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 28 |
| | $ | 19 |
|
| Receivables — | | | | |
| Energy marketing receivable | | 493 |
| | 623 |
|
| Customer accounts receivable | | 453 |
| | 364 |
|
| Unbilled revenues | | 173 |
| | 239 |
|
| Other accounts and notes receivable | | 69 |
| | 76 |
|
| Accumulated provision for uncollectible accounts | | (37 | ) | | (27 | ) |
| Materials and supplies | | 25 |
| | 26 |
|
| Natural gas for sale | | 346 |
| | 631 |
|
| Prepaid income taxes | | — |
| | 24 |
|
| Prepaid expenses | | 54 |
| | 55 |
|
| Assets from risk management activities, net of collateral | | 138 |
| | 128 |
|
| Other regulatory assets, current | | 60 |
| | 81 |
|
| Other current assets | | 16 |
| | 11 |
|
| Total current assets | | 1,818 |
| | 2,250 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 14,660 |
| | 14,508 |
|
| Less: Accumulated depreciation | | 4,498 |
| | 4,439 |
|
| Plant in service, net of depreciation | | 10,162 |
| | 10,069 |
|
| Construction work in progress | | 625 |
| | 496 |
|
| Total property, plant, and equipment | | 10,787 |
| | 10,565 |
|
| Other Property and Investments: | | | | |
| Goodwill | | 5,967 |
| | 5,967 |
|
| Equity investments in unconsolidated subsidiaries | | 1,604 |
| | 1,541 |
|
Other intangible assets, net of amortization of $60 and $34
at March 31, 2017 and December 31, 2016, respectively | | 340 |
| | 366 |
|
| Miscellaneous property and investments | | 21 |
| | 21 |
|
| Total other property and investments | | 7,932 |
| | 7,895 |
|
| Deferred Charges and Other Assets: | | | | |
| Other regulatory assets, deferred | | 958 |
| | 973 |
|
| Other deferred charges and assets | | 188 |
| | 170 |
|
| Total deferred charges and other assets | | 1,146 |
| | 1,143 |
|
| Total Assets | | $ | 21,683 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At March 31, 2017 | | At December 31, 2016 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 22 |
| | $ | 22 |
|
| Notes payable | | 1,023 |
| | 1,257 |
|
| Energy marketing trade payables | | 471 |
| | 597 |
|
| Accounts payable | | 241 |
| | 348 |
|
| Customer deposits | | 131 |
| | 153 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 50 |
| | 26 |
|
| Other accrued taxes | | 63 |
| | 68 |
|
| Accrued interest | | 59 |
| | 48 |
|
| Accrued compensation | | 43 |
| | 58 |
|
| Liabilities from risk management activities, net of collateral | | 18 |
| | 62 |
|
| Other regulatory liabilities, current | | 148 |
| | 102 |
|
| Accrued environmental remediation, current | | 66 |
| | 69 |
|
| Temporary LIFO liquidation | | 126 |
| | — |
|
| Other current liabilities | | 124 |
| | 108 |
|
| Total current liabilities | | 2,585 |
| | 2,918 |
|
| Long-term Debt | | 5,246 |
| | 5,259 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 2,059 |
| | 1,975 |
|
| Employee benefit obligations | | 434 |
| | 441 |
|
| Other cost of removal obligations | | 1,630 |
| | 1,616 |
|
| Accrued environmental remediation, deferred | | 343 |
| | 357 |
|
| Other regulatory liabilities, deferred | | 54 |
| | 51 |
|
| Other deferred credits and liabilities | | 88 |
| | 127 |
|
| Total deferred credits and other liabilities | | 4,608 |
| | 4,567 |
|
| Total Liabilities | | 12,439 |
| | 12,744 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, par value $0.01 per share — | | | | |
| Authorized — 100 million shares | | | | |
| Outstanding — 100 shares | | — |
| | — |
|
| Paid in capital | | 9,104 |
| | 9,095 |
|
| Retained earnings (accumulated deficit) | | 116 |
| | (12 | ) |
| Accumulated other comprehensive income | | 24 |
| | 26 |
|
| Total stockholder's equity | | 9,244 |
| | 9,109 |
|
| Total Liabilities and Stockholder's Equity | | $ | 21,683 |
| | $ | 21,853 |
|
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
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 are also involved in several other complementary businesses.
Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K) to the Condensed Financial Statements herein and "BUSINESS – Southern Company Gas" in Item 1 of the Form 10-K.
Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas 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 Southern Company Gas for the foreseeable future.
Merger with Southern Company
On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company 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 Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a 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 (I) to the Condensed Financial Statements herein for additional information relating to the Merger.
Investment in SNG
In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $34 million from this investment in the first quarter 2017. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
Other Matters
In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar.
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.
Heating Degree Days
Southern Company Gas 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 Southern Company Gas' distribution system. With the exception of Southern Company Gas' utilities in Illinois and Florida, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Illinois and the gas marketing services customers primarily in Georgia can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges at gas distribution operations and gas marketing services to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining all of the earnings upside in the event of colder-than-normal weather for gas distribution operations in Illinois and most of the earnings upside for gas marketing services. The following table presents the Heating Degree Days information for Illinois and Georgia.
|
| | | | | | | | | | | | | | |
| | First Quarter | | 2017 vs. 2016 | | 2017 vs. normal |
| | Normal(a) | | 2017 | | 2016 | | (warmer) | | (warmer) |
Illinois(b) | 3,121 |
| | 2,560 |
| | 2,701 |
| | (5 | )% | | (18 | )% |
| Georgia | 1,499 |
| | 925 |
| | 1,334 |
| | (31 | )% | | (38 | )% |
| |
| (a) | Normal represents the 10-year average from January 1, 2007 through March 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 2,902 for the first three months from 1998 through 2007. |
For the successor first quarter 2017, weather in Illinois was 18% warmer than normal and 5% warmer than the predecessor first quarter 2016. Southern Company Gas hedged its exposure at Nicor Gas to warmer-than-normal weather for the first quarter 2017 and 2016; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $6 million for both the successor first quarter 2017 and the predecessor first quarter 2016.
For the successor first quarter 2017, weather in Georgia was 38% warmer than normal and 31% warmer than the predecessor first quarter 2016. Southern Company Gas hedged its exposure at gas marketing services to warmer-than-normal weather for the first quarter 2017 and 2016; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $7 million for the successor first quarter 2017. For the predecessor first quarter 2016, the positive weather-related pre-tax income impact on gas marketing services was $1 million as a result of the hedging program.
Customer Count
The number of customers at gas distribution operations and energy customers at 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 and Illinois. The following table provides the number of customers served by Southern Company Gas at March 31, 2017 and 2016.
|
| | | | | | | | |
| | March 31, | | |
| | 2017 | | 2016 | | 2017 vs. 2016 |
| | (in thousands, except market share %) | (% change) |
| Gas distribution operations | 4,618 |
| | 4,594 |
| | 0.5 | % |
| Gas marketing services | | | | | |
| Energy customers | 661 |
| | 662 |
| | (0.2 | )% |
| Market share of energy customers in Georgia | 29.3 | % | | 29.3 | % | |
|
| Service contracts | 1,197 |
| | 1,204 |
| | (0.6 | )% |
Southern Company Gas anticipates overall customer growth trends at gas distribution operations to continue in 2017, as it expects continued improvement in the new housing market and low natural gas prices.
Gas marketing services' market share in Georgia was flat at March 31, 2017 compared to March 31, 2016 despite the highly competitive marketing environment, which Southern Company Gas expects for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Volumes of Natural Gas Sold
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services, as shown in the following table, illustrate the effects of warm weather and low customer demand for natural gas compared to the prior year. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
|
| | | | | | | | |
| | First Quarter | | 2017 vs. 2016 |
| | 2017 | | 2016 | | % Change |
Gas distribution operations (mmBtu in millions) | | | | | |
| Firm | 263 |
| | 289 |
| | (9.0 | )% |
| Interruptible | 25 |
| | 26 |
| | (3.8 | )% |
| Total | 288 |
| | 315 |
| | (8.6 | )% |
Gas marketing services (mmBtu in millions) | | | | | |
| Firm: | | | | | |
| Georgia | 12 |
| | 17 |
| | (29.4 | )% |
| Illinois | 5 |
| | 6 |
| | (16.7 | )% |
| Other emerging markets | 5 |
| | 5 |
| | — | % |
| Interruptible: | | | | | |
| Large commercial and industrial | 4 |
| | 4 |
| | — | % |
| Total | 26 |
| | 32 |
| | (18.8 | )% |
Wholesale gas services (mmBtu in millions/day) | | | | | |
| Daily physical sales | 6.7 |
| | 7.9 |
| | (15.2 | )% |
Seasonality of Results
During the months of November through March, 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. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs are incurred relatively evenly during a 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 Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income
Net income attributable to Southern Company Gas for the successor first quarter 2017 was $239 million. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor period. Net income was positively impacted by $3 million due to the pushdown of acquisition accounting related to the Merger. Net income for the successor period included $15 million in after-tax earnings from the SNG investment, net of related interest expense, as well as $29 million and $48 million in after-tax mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas price volatility. Also reflected in net income for this period was an increase of $11 million, after-tax, from additional infrastructure replacement programs at gas distribution operations and a base rate increase at Atlanta Gas Light effective March 1, 2017, partially offset by a reduction of $8 million, after-tax, resulting from warmer-than-normal weather, net of hedging.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net income attributable to Southern Company Gas for the predecessor first quarter 2016 was $182 million. Net income attributable to the noncontrolling interest in SouthStar for the predecessor period was $11 million. Net income of $193 million for the predecessor period reflected $12 million and $26 million in after-tax mark-to-market gains from derivative instruments and commercial activity revenue, respectively, at wholesale gas services due to changes in natural gas price volatility in the period, partially offset by a decrease of $3 million, after-tax, attributable to warmer-than-normal weather, net of hedging.
Natural Gas Revenues
Natural gas revenues for the successor first quarter 2017 and the predecessor first quarter 2016 were $1.5 billion and $1.3 billion, respectively.
Natural gas revenues for the successor first quarter 2017 included a $5 million favorable impact from fair value adjustments to certain assets and liabilities in the application of acquisition accounting for gas marketing services and wholesale gas services as well as $48 million and $80 million in mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas price volatility. Natural gas revenues also reflect the increase in cost of natural gas discussed below, $19 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs, as well as a rate increase that became effective in March 2017 for Atlanta Gas Light, partially offset by decreases in revenues of $13 million attributable to warmer-than-normal weather, net of hedging.
Natural gas revenues for the predecessor first quarter 2016 reflected $20 million and $43 million in mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas price volatility, partially offset by decreases in revenues of $5 million attributable to warmer-than-normal weather, net of hedging.
Natural gas distribution rates include provisions to adjust billings for fluctuation in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations.
Cost of Natural Gas
Cost of natural gas was $719 million for the successor first quarter 2017 and $571 million for the predecessor first quarter 2016, which primarily reflected an increase of 54% in natural gas prices during the first quarter 2017 compared to the prior period, along with lower demand for natural gas driven by warmer-than-normal weather. See OVERVIEW – "Operating Metrics – Heating Degree Days" herein for additional information regarding the effects of weather.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses were $253 million for the successor first quarter 2017 and $241 million for the predecessor first quarter 2016. Other operations and maintenance expense for the successor period reflected additional compensation expense in the period due to the timing of accruals and increased pipeline compliance and maintenance activities, partially offset by low bad debt expense as a result of warmer-than-normal weather.
Depreciation and Amortization
Depreciation and amortization was $120 million for the successor first quarter 2017 and $102 million for the predecessor first quarter 2016. Included in depreciation and amortization for the successor first quarter 2017 was $10 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, as well as additional depreciation at gas distribution operations due to an $879 million increase in gross property, plant, and equipment since March 31, 2016.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Taxes Other Than Income Taxes
For the successor first quarter 2017 and the predecessor first quarter 2016, taxes other than income taxes were $70 million and $62 million, respectively, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes. Taxes other than income taxes in the successor period reflected increased revenue-based taxes due to higher revenues at gas distribution operations in the period.
Earnings from Equity Method Investments
For the successor first quarter 2017, earnings from equity method investments were $39 million, which primarily consists of $34 million in earnings from SNG and $3 million in earnings from PennEast Pipeline. For the predecessor first quarter 2016, earnings from equity method investments were not material.
See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.
Interest Expense, Net of Amounts Capitalized
For the successor first quarter 2017, interest expense, net of amounts capitalized, was $46 million, reflecting the $9 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by additional interest expense on new debt issuances in 2016.
For the predecessor first quarter 2016, interest expense, net of amounts capitalized, was $48 million.
Income Taxes
For the successor first quarter 2017, income taxes were $150 million, driven by pre-tax earnings.
For the predecessor first quarter 2016, income taxes were $111 million.
Performance and Non-GAAP Measures
Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (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, which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor first quarter 2017 presented herein is considered a non-GAAP measure. Southern Company Gas 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. Southern Company Gas further believes that the presentation of segment EBIT for the successor first quarter 2017 is useful as it allows for a measure of comparability to the 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, respectively, are provided herein.
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus 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 consolidated 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. Southern Company Gas 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 adjusted operating
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
margin 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, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | First Quarter 2017 | | | First Quarter 2016 |
| | (in millions) | | | (in millions) |
| Operating Income | $ | 391 |
| | | $ | 348 |
|
Other operating expenses(a) | 443 |
| | | 408 |
|
Revenue taxes(b) | (47 | ) | | | (39 | ) |
| Adjusted Operating Margin | $ | 787 |
| | | $ | 717 |
|
| |
| (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. |
|
| | | |
| | Predecessor |
| | First Quarter 2016 |
| | (in millions) |
| Consolidated Net Income Attributable to Southern Company Gas | $ | 182 |
|
| Net income attributable to noncontrolling interest | 11 |
|
| Income taxes | 111 |
|
| Interest expense, net of amounts capitalized | 48 |
|
| EBIT | $ | 352 |
|
Segment Information
Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below. See Note (K) to the Condensed Financial Statements herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | First Quarter 2017 | | | First Quarter 2016 |
| | Adjusted Operating | | Operating | | Net | | | Adjusted Operating | | Operating | |
|
| | Margin(*) | | Expenses(*) | | Income | | | Margin(*) | | Expenses(*) | | EBIT |
| | (in millions) | | | (in millions) |
| Gas distribution operations | $ | 542 |
| | $ | 313 |
| | $ | 117 |
| | | $ | 525 |
| | $ | 291 |
| | $ | 235 |
|
| Gas marketing services | 105 |
| | 53 |
| | 31 |
| | | 124 |
| | 44 |
| | 80 |
|
| Wholesale gas services | 131 |
| | 15 |
| | 68 |
| | | 60 |
| | 17 |
| | 44 |
|
| Gas midstream operations | 9 |
| | 12 |
| | 15 |
| | | 9 |
| | 12 |
| | (1 | ) |
| All other | 2 |
| | 5 |
| | 8 |
| | | 2 |
| | 7 |
| | (5 | ) |
| Intercompany eliminations | (2 | ) | | (2 | ) | | — |
| | | (3 | ) | | (2 | ) | | (1 | ) |
| Consolidated | $ | 787 |
| | $ | 396 |
| | $ | 239 |
| | | $ | 717 |
| | $ | 369 |
| | $ | 352 |
|
| |
| (*) | Operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' 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 Southern Company Gas the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, such as depreciation, interest, maintenance, and overhead costs, as well as to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' 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. Southern Company Gas 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 utilities' service territories.
Successor first quarter 2017
Net income of $117 million includes $542 million in adjusted operating margin, $313 million in operating expenses, and $4 million in other income (expense), net, which resulted in EBIT of $233 million. Net income also includes $40 million in interest expense and $76 million in income tax expense. Adjusted operating margin reflects $19 million in additional revenue from the continued investment in infrastructure replacement programs and a base rate increase at Atlanta Gas Light effective March 1, 2017, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect additional depreciation due to continued investment in infrastructure programs, additional employee compensation in the period due to the timing of accruals for certain expenses, and increased pipeline compliance and maintenance activities.
Predecessor first quarter 2016
EBIT of $235 million includes $525 million in adjusted operating margin, $291 million in operating expenses, and $1 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.
Gas Marketing Services
Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets. 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.
Successor first quarter 2017
Net income of $31 million includes $105 million in adjusted operating margin and $53 million in operating expenses, which resulted in EBIT of $52 million. Net income also includes $1 million in interest expense and $20 million in income tax expense. As a result of purchasing the remaining interest in SouthStar in October 2016, there was no noncontrolling interest and all net income from gas marketing services was attributable to Southern Company Gas in this period. Adjusted operating margin, which includes gas marketing and warranty sales, reflects $2 million of additional revenue as a result of fair value adjustments to certain assets and liabilities in the application of acquisition accounting, as well as a $7 million negative impact of warmer-than-normal weather, net of hedging and $7 million in unrealized hedge losses in the period. Operating expenses reflect $10 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting, and a reduction in litigation-related expense.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Predecessor first quarter 2016
EBIT of $80 million includes $124 million in adjusted operating margin and $44 million in operating expenses. Adjusted operating margin reflects revenue from gas marketing and warranty sales, $2 million in unrealized hedge gains, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather in the period. Operating expenses primarily reflect marketing, legal, and bad debt expenses. Earnings in the predecessor period include $11 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. Southern Company Gas has positioned the business to generate positive economic earnings 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.
Successor first quarter 2017
Net income of $68 million includes $131 million in adjusted operating margin and $15 million in operating expenses, which resulted in EBIT of $116 million. Also included is $2 million in interest expense and $46 million in income tax expense. Operating expenses primarily reflect employee compensation and benefits.
Predecessor first quarter 2016
EBIT of $44 million includes $60 million in adjusted operating margin, $17 million in operating expense, and $1 million in other income (expense), net. Operating expenses primarily reflect employee compensation and benefits.
The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | First Quarter 2017 | | | First Quarter 2016 |
| | (in millions) | | | (in millions) |
| Commercial activity recognized | $ | 80 |
| | | $ | 43 |
|
| Gain (loss) on storage derivatives | 4 |
| | | (2 | ) |
| Gain (loss) on transportation and forward commodity derivatives | 44 |
| | | 22 |
|
| LOCOM adjustments, net of current period recoveries | — |
| | | (3 | ) |
| Purchase accounting adjustments to fair value inventory and contracts | 3 |
| | | — |
|
| Adjusted Operating Margin | $ | 131 |
| | | $ | 60 |
|
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. Increases in natural gas supply and warmer-than-normal weather during the 2016/2017 Heating Season and the resulting higher natural gas inventories at the end of 2016 caused natural gas prices to decline in the early part of 2017. However, as natural gas prices and forward storage or time spreads increased, largely in the first quarter 2017, wholesale gas services was able to capture higher storage values to accommodate the increase in natural gas supply. Wholesale gas services experienced low volatility in 2016 due partly to weather and Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.
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
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
a significant impact on Southern Company Gas' 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. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first quarter 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to continued supply constraints and increases in natural gas supply and warmer-than-normal weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.
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 March 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 schedule | | |
| | Total storage
(WACOG $2.74) | | Expected net operating gains(a) | | Physical transportation transactions – expected net operating losses(b) |
| | (in mmBtu in millions) | | (in millions) | | (in millions) |
| 2017 | 40.3 |
| | $ | 14 |
| | $ | (21 | ) |
| 2018 and thereafter | 5.2 |
| | 4 |
| | (23 | ) |
| Total at March 31, 2017 | 45.5 |
| | $ | 18 |
| | $ | (44 | ) |
| |
| (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. |
| |
| (b) | Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains that were previously recognized. |
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and, based on current expectations, primarily will be reversed during the remainder of 2017 when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
Gas Midstream Operations
Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments consist of the SNG interest, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc.
Successor first quarter 2017
Net income of $15 million includes $9 million in adjusted operating margin, $12 million in operating expenses, $38 million in earnings from equity method investments, which consists primarily of equity in earnings from the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
investment in SNG, and $1 million in other income (expense), net, which resulted in EBIT of $36 million. Also included in net income are $9 million in interest expense and $12 million in income tax expense.
Predecessor first quarter 2016
Loss before interest and taxes of $1 million includes $9 million in adjusted operating margin, $12 million in operating expenses, and $2 million of other income (expense), net.
All Other
All other includes Southern Company Gas' 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. For the successor first quarter 2017 and the predecessor first quarter 2016, these operating expenses included Merger-related expenses of less than $1 million and $3 million, respectively.
Segment Reconciliations
Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor first quarter 2017, and operating income to adjusted operating margin for the periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein for additional information. |
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | First Quarter 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Consolidated Net Income | $ | 117 |
| $ | 31 |
| $ | 68 |
| $ | 15 |
| $ | 8 |
| $ | — |
| $ | 239 |
|
| Income taxes | 76 |
| 20 |
| 46 |
| 12 |
| (4 | ) | — |
| 150 |
|
Interest expense, net of
amounts capitalized | 40 |
| 1 |
| 2 |
| 9 |
| (6 | ) | — |
| 46 |
|
| EBIT | $ | 233 |
| $ | 52 |
| $ | 116 |
| $ | 36 |
| $ | (2 | ) | $ | — |
| $ | 435 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | First Quarter 2017 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 229 |
| $ | 52 |
| $ | 116 |
| $ | (3 | ) | $ | (3 | ) | $ | — |
| $ | 391 |
|
Other operating expenses(a) | 360 |
| 53 |
| 15 |
| 12 |
| 5 |
| (2 | ) | 443 |
|
Revenue tax expense(b) | (47 | ) | — |
| — |
| — |
| — |
| — |
| (47 | ) |
| Adjusted Operating Margin | $ | 542 |
| $ | 105 |
| $ | 131 |
| $ | 9 |
| $ | 2 |
| $ | (2 | ) | $ | 787 |
|
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | | | | | | | | | | | | | | | | |
| | Predecessor |
| | First Quarter 2016 |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services | Gas Midstream Operations | All Other | Intercompany Elimination | Consolidated |
| | (in millions) |
| Operating Income (Loss) | $ | 234 |
| $ | 80 |
| $ | 43 |
| $ | (3 | ) | $ | (5 | ) | $ | (1 | ) | $ | 348 |
|
Other operating expenses(a) | 330 |
| 44 |
| 17 |
| 12 |
| 7 |
| (2 | ) | 408 |
|
Revenue tax expense(b) | (39 | ) | — |
| — |
| — |
| — |
| — |
| (39 | ) |
| Adjusted Operating Margin | $ | 525 |
| $ | 124 |
| $ | 60 |
| $ | 9 |
| $ | 2 |
| $ | (3 | ) | $ | 717 |
|
| |
| (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. |
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of its primary business of natural gas distribution and complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' 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, Southern Company Gas' ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of 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 natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by economic growth. The pace of economic growth and natural gas demand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Current proposals related to potential tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.
Volatility of natural gas prices has a significant impact on Southern Company Gas' 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 Southern Company Gas' 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.
For additional information relating to these issues, see "Risk Factors" of Southern Company Gas in Item 1A of the Form 10-K.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Investment in SNG" and Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.
Environmental Matters
Compliance costs related to federal and state environmental statutes and regulations 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. Further, higher 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. See Note (B) under "Environmental Remediation" to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Regulatory Matters
See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (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, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program, Integrated System Reinforcement Program, and Integrated Customer Growth Program, 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.
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 Georgia PSC allowed the last monthly Pipeline Replacement Program surcharge increase, originally scheduled for October 2017, to occur effective March 1, 2017.
In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase is based on a projected 12-month test year ending March 31, 2017 and an ROE of 10.25%. The New Jersey BPU is expected to issue an order on the filing in the third quarter 2017, after which rate adjustments will be effective.
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and an ROE of
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase is based on a projected 12-month test year beginning September 1, 2017 and an ROE of 10.25%. The requested increase includes $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. The Virginia Commission is expected to rule on the requested increase in the first quarter 2018. Rate adjustments are expected to be effective September 1, 2017, subject to refund.
The ultimate outcome of the pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $24 million of qualifying assets during the first quarter 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and liquefied natural gas facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $38 million during the first quarter 2017.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (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 recovery of and return on current and future capital investments under the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was approved by the Georgia PSC on February 21, 2017. See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $3 million during the first quarter 2017.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $7 million during the first quarter 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program in 2015. Under the program, Florida City Gas invested $3 million during the first quarter 2017.
Other Matters
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ordinary course of business. The ultimate outcome of such pending or potential litigation against Southern Company Gas cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in 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 Southern Company Gas' 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 Southern Company Gas' financial statements.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term. For such arrangements, Southern Company Gas expects that the revenue from contracts with these customers will continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company Gas has not elected its transition method.
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 annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
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 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 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 annual periods beginning after December 15, 2017, including interim periods within those annual periods. Southern Company Gas is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' 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 adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor first quarter 2017 and the predecessor first quarter 2016. See OVERVIEW – "Merger with Southern Company" herein for additional information.
Southern Company Gas' financial condition remained stable at March 31, 2017. Southern Company Gas 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" 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. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's 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. As of March 31, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $722 million. These restrictions
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Net cash provided from operating activities totaled $758 million for the successor first quarter 2017 and $841 million for the predecessor first quarter 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.
Net cash used for investing activities totaled $405 million for the successor first quarter 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $238 million for the predecessor first quarter 2016, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations.
Net cash used for financing activities totaled $344 million for the successor first quarter 2017, primarily due to net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash used for financing activities totaled $602 million for the predecessor first quarter 2016, primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes at March 31, 2017 include an increase of $222 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs and decreases of $411 million in natural gas for sale, including temporary LIFO liquidation due to the use of natural gas stored during the first quarter 2017, and $234 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include decreases of $107 million in accounts payable as well as $130 million and $126 million in energy marketing receivable and energy marketing payables, respectively, due to lower natural gas prices.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. Approximately $22 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein 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 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. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.
Sources of Capital
Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
At March 31, 2017, Southern Company Gas' current liabilities exceeded current assets by $767 million. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund its daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At March 31, 2017, Southern Company Gas had approximately $28 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expires | | | | | | Expires Within One Year |
| Company | | 2017 | | 2018 | | Total | | Unused | | Term Out | | No Term Out |
| | | (in millions) |
| Southern Company Gas Capital | | $ | 49 |
| | $ | 1,251 |
| | $ | 1,300 |
| | $ | 1,249 |
| | $ | — |
| | $ | 49 |
|
| Nicor Gas | | 26 |
| | 674 |
| | 700 |
| | 700 |
| | — |
| | 26 |
|
| Total | | $ | 75 |
| | $ | 1,925 |
| | $ | 2,000 |
| | $ | 1,949 |
| | $ | — |
| | $ | 75 |
|
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 have been issued totaling $200 million.
See Note 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The Southern Company Gas Credit Facility and the Nicor Gas Credit Facility included in the table above each contain a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of the applicable company. Such cross acceleration provisions to other indebtedness would trigger an event of default if Southern Company Gas defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, each of the applicable companies was in compliance with all such covenants. Neither of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, the applicable company expects to renew or replace its bank credit arrangements 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.
Southern Company Gas 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.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | |
| | Short-term Debt at March 31, 2017 | | Short-term Debt During the Period(*) |
| | Amount
Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| Commercial paper: | (in millions) | | | | (in millions) | | | | (in millions) |
| Southern Company Gas Capital | $ | 715 |
| | 1.28 | % | | $ | 630 |
| | 1.09 | % | | $ | 733 |
|
| Nicor Gas | 308 |
| | 1.16 |
| | 410 |
| | 0.98 |
| | 525 |
|
| Short-term loans: | | | | | | | | | |
| Southern Company Gas | — |
| | — |
| | 1 |
| | 1.91 |
| | 113 |
|
| Total | $ | 1,023 |
| | 1.24 | % | | $ | 1,041 |
| | 1.04 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the successor three-month period ended March 31, 2017. |
Southern Company Gas believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
Southern Company Gas 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 requirements under these contracts at March 31, 2017 were $13 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 Gas 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 Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.
Financing Activities
The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of March 31, 2017, the non-principal components totaled $556 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas 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.
Market Price Risk
Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor first quarter 2017. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also, see Notes (C) and (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern Company Gas 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 Southern Company Gas that sell natural gas directly to its end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas 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, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower 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 energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | First Quarter | | | First Quarter |
| | 2017 | | | 2016 |
| | (in millions) | | | (in millions) |
| Contracts outstanding at beginning of period, assets (liabilities), net | $ | 12 |
| | | $ | 75 |
|
| Contracts realized or otherwise settled | 4 |
| | | (85 | ) |
Current period changes(a) | 48 |
| | | (34 | ) |
| Contracts outstanding at the end of period, assets (liabilities), net | 64 |
| | | (44 | ) |
| Netting of cash collateral | 92 |
| | | 165 |
|
Cash collateral and net fair value of contracts outstanding at end of period(b) | $ | 156 |
| | | $ | 121 |
|
| |
| (a) | Current period changes also include the fair value of new contracts entered into during the period, if any. |
| |
| (b) | Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $19 million at March 31, 2017 and $9 million at March 31, 2016. |
The maturities of Southern Company Gas' energy-related derivative contracts at March 31, 2017 were as follows:
|
| | | | | | | | | | | | | | | |
| | | | Fair Value Measurements |
| | | | Successor – March 31, 2017 |
| | Total
Fair Value | | Maturity |
| | | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| | (in millions) |
Level 1(a) | $ | (28 | ) | | $ | (2 | ) | | $ | (21 | ) | | $ | (5 | ) |
Level 2(b) | 92 |
| | 57 |
| | 29 |
| | 6 |
|
| Level 3 | — |
| | — |
| | — |
| | — |
|
Fair value of contracts outstanding at end of period(c) | $ | 64 |
| | $ | 55 |
| | $ | 8 |
| | $ | 1 |
|
| |
| (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 $92 million at March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
| | |
| Note | | Page Number |
| A | | |
| B | | |
| C | | |
| D | | |
| E | | |
| F | | |
| G | | |
| H | | |
| I | | |
| J | | |
| K | | |
INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT
The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.
|
| |
| Registrant | Applicable Notes |
| Southern Company | A, B, C, D, E, F, G, H, I, J, K |
| Alabama Power | A, B, C, E, F, G, H |
| Georgia Power | A, B, C, E, F, G, H |
| Gulf Power | A, B, C, E, F, G, H |
| Mississippi Power | A, B, C, E, F, G, H |
| Southern Power | A, B, C, D, E, G, H, I |
| Southern Company Gas | A, B, C, E, F, G, H, I, J, K |
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)
The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 20152016 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2016March 31, 2017 and 2015.2016. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows since July 1, 2016for the three months ended March 31, 2017 and financial condition as of September 30,March 31, 2017 and December 31, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (SNG),SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company – Merger with Southern Company Gas" and " – Investment in Southern Natural Gas" for additional information regarding the Merger.
Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas 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 consolidated financial statements of Southern Company Gas 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 Southern Company Gas' investment in SNG, respectively.condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Recently Issued Accounting Standards
In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 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.
While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term. For such arrangements, the registrants expect that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.
The registrants' ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606. Given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income.
The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the registrants have not elected a transition method.
On February 25, 2016,January 26, 2017, the FASB issued ASU No. 2016-02,2017-04, Leases(Topic 842)Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2016-02)2017-04). ASU 2016-022017-04 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 annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017.
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 lesseesthat 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 recognize onbe separately presented in the balance sheet a lease liability and a right-of-use assetincome statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all leases.cost components remain eligible for capitalization under FERC regulations. ASU 2016-02 also changes2017-07 will be applied retrospectively for the recognition, measurement, and presentation of expense associated with leasesthe service cost component and provides clarification regarding the identification of certainother components of contracts that would representnet periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases.prospective basis. ASU 2016-022017-07 is effective for fiscal yearsannual periods beginning after December 15, 2018, with early adoption2017, including interim periods within those annual periods. Southern Company, the traditional
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
permitted. The registrantselectric operating companies, and Southern Company Gas are currently evaluating the new standardstandard. The presentation changes required for net periodic pension and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to havepostretirement benefit costs will result in a significant impact on the registrants' balance sheets.
On March 30, 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. Most significantly, 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 benefitdecrease in the income statement. Southern Company andCompany's, the traditional electric operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permittedcompanies', and Southern Company Gas' operating income and the traditional electrican increase in other income for 2016 and 2017 and are expected to result in a decrease in operating companies intend to adopt the ASUincome and an increase in the fourth quarter 2016.other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company andCompany's, the traditional electric operating companies.companies', or Southern Company Gas' financial statements.
Affiliate Transactions
In 2014, priorPrior to Southern Company's acquisitionthe completion of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, Georgia Power entered into two agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. Payments of approximately $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.
Prior to Southern Company Gas' completionacquisition of its acquisition of a 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern CompanyPower) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies,Alabama Power, Georgia Power, Southern Power, and Southern Company Gas 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 period subsequent to Southern Company Gas' investment in SNG,three months ended March 31, 2017, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 millionunder these agreements for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, GulfSouthern Power, and MississippiSouthern Company Gas were approximately $1 million, $26 million, $6 million, and $9 million, respectively.
SCS, as agent for Southern Power, under "Asset Retirement Obligationshas agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the three months ended March 31, 2017, natural gas purchases made by Southern Power from Southern Company Gas' subsidiaries were approximately $23 million.
Goodwill and Other CostsIntangible Assets
As of Removal" in Item 8March 31, 2017 and December 31, 2016, goodwill was as follows: |
| | | |
| | Goodwill |
| | (in millions) |
| Southern Company | $ | 6,251 |
|
| Southern Power | $ | 2 |
|
| Southern Company Gas |
|
|
| Gas distribution operations | $ | 4,702 |
|
| Gas marketing services | 1,265 |
|
| Southern Company Gas total | $ | 5,967 |
|
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of the Form 10-K for additional information regarding Southern Company's and the traditional electric operating companies' asset retirement obligations (ARO) and the EPA's regulation of CCR. See Note 1 to the financial statements of Southern Power under "Asset Retirement Obligations" in Item 8 of the Form 10-K for additional information regarding Southern Power's AROs.
The cost estimates below are based on information as of September 30, 2016. The cost estimates for AROs related to the disposal of CCR are based on 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 Disposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in placeeach year, or by other methods. 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 traditional electric operating companies expect to continue to periodically update these estimates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, details of the AROs included in the registrants' Condensed Balance SheetsOther intangible assets were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) |
| Balance at beginning of year | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 41 |
| | 5 |
| | — |
| | — |
| | 15 |
| | 18 |
|
| Liabilities settled | (117 | ) | | (12 | ) | | (93 | ) | | — |
| | (12 | ) | | — |
|
| Accretion | 119 |
| | 55 |
| | 56 |
| | 2 |
| | 3 |
| | 1 |
|
| Cash flow revisions | 712 |
| | 31 |
| | 675 |
| | 2 |
| | 7 |
| | — |
|
| Balance at end of period | $ | 4,514 |
| | $ | 1,527 |
| | $ | 2,554 |
| | $ | 134 |
| | $ | 190 |
| | $ | 40 |
|
The traditional electric operating companies' increases in cash flow revisions for the nine months ended September 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power reflects its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.
Goodwill and Other Intangible Assets
As of September 30, 2016, goodwill was as follows: |
| | | |
| | As of September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 6,223 |
|
| Southern Power | $ | 2 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | As of March 31, 2017 | | As of December 31, 2016 |
| | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other
Intangible Assets, Net |
| | (in millions) | | (in millions) |
| Southern Company | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Customer relationships | $ | 268 |
| $ | (44 | ) | $ | 224 |
| | $ | 268 |
| $ | (32 | ) | $ | 236 |
|
| Trade names | 158 |
| (8 | ) | 150 |
| | 158 |
| (5 | ) | 153 |
|
| Patents | 4 |
| — |
| 4 |
| | 4 |
| — |
| 4 |
|
| Backlog | 5 |
| (1 | ) | 4 |
| | 5 |
| (1 | ) | 4 |
|
| Storage and transportation contracts | 64 |
| (15 | ) | 49 |
| | 64 |
| (2 | ) | 62 |
|
| Software and other | 2 |
| (1 | ) | 1 |
| | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 456 |
| (28 | ) | 428 |
| | 456 |
| (22 | ) | 434 |
|
| Total other intangible assets subject to amortization | $ | 957 |
| $ | (97 | ) | $ | 860 |
| | $ | 957 |
| $ | (62 | ) | $ | 895 |
|
| Other intangible assets not subject to amortization: | | | | | | | |
| Federal Communications Commission licenses | $ | 75 |
| $ | — |
| $ | 75 |
| | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | $ | 1,032 |
| $ | (97 | ) | $ | 935 |
| | $ | 1,032 |
| $ | (62 | ) | $ | 970 |
|
| | | | | | | | |
| Southern Power | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| PPA fair value adjustments | $ | 456 |
| $ | (28 | ) | $ | 428 |
| | $ | 456 |
| $ | (22 | ) | $ | 434 |
|
| | | | | | | | |
| Southern Company Gas | | | | | | | |
| Other intangible assets subject to amortization: | | | | | | | |
| Gas marketing services | | | | | | | |
| Customer relationships | $ | 221 |
| $ | (41 | ) | $ | 180 |
| | $ | 221 |
| $ | (30 | ) | $ | 191 |
|
| Trade names | 115 |
| (4 | ) | 111 |
| | 115 |
| (2 | ) | 113 |
|
| Wholesale gas services | | | | | | | |
| Storage and transportation contracts | 64 |
| (15 | ) | 49 |
| | 64 |
| (2 | ) | 62 |
|
| Total other intangible assets subject to amortization | $ | 400 |
| $ | (60 | ) | $ | 340 |
| | $ | 400 |
| $ | (34 | ) | $ | 366 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016, other intangible assets were as follows:
|
| | | | | | | | | | |
| | | As of September 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| | | (in millions) |
| Southern Company | | | | |
| Other intangible assets subject to amortization: | | | | |
| Customer relationships | 11-26 years | $ | 268 |
| $ | (16 | ) | $ | 252 |
|
| Trade names | 5-28 years | 158 |
| (3 | ) | 155 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Storage and transportation contracts | 1-5 years | 64 |
| (4 | ) | 60 |
|
| Software and other | 1-12 years | 2 |
| — |
| 2 |
|
| PPA fair value adjustments | 19-20 years | 405 |
| (16 | ) | 389 |
|
| Total other intangible assets subject to amortization | | $ | 906 |
| $ | (39 | ) | $ | 867 |
|
| Other intangible assets not subject to amortization: | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| Total other intangible assets | | $ | 981 |
| $ | (39 | ) | $ | 942 |
|
| | | | | |
| Southern Power | | | | |
| Other intangible assets subject to amortization: | | | | |
| PPA fair value adjustments | 19-20 years | $ | 405 |
| $ | (16 | ) | $ | 389 |
|
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| | Three Months Ended | Nine Months Ended |
| | September 30, 2016 |
| | (in millions) |
| Southern Company | $ | 25 |
| $ | 27 |
|
| Southern Power | $ | 2 |
| $ | 4 |
|
At December 31, 2015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and Southern Company Gas on July 1, 2016. |
| | | |
| | Three Months Ended |
| | March 31, 2017 |
| | (in millions) |
| Southern Company | $ | 35 |
|
| Southern Power | $ | 6 |
|
| Southern Company Gas | $ | 26 |
|
See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments.adjustments related to its business acquisitions. Also see Note (I) under "Southern Company – Acquisition of PowerSecure International, Inc." and " – Merger with Southern Company Gas" for additional information.
Property Damage Reserve
See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.
Gulf Power's 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 is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals, but is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the storm reserve to approximately $40 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.
Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG)WACOG basis.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (LIFO)LIFO basis. Inventory decrements occurring during the year that are restored prior to year-endyear end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-endyear end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas' inventory decrement at March 31, 2017 is expected to be restored prior to year end. 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.
or Southern Company Gas' other naturalnet 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. Southern Company Gas recorded no LOCOM adjustment in the successor first quarter 2017 and recorded a $3 million LOCOM adjustment in the predecessor first quarter 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (B) | CONTINGENCIES AND REGULATORY MATTERS |
See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.
General Litigation Matters
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege 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 seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.
Each registrant is 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 air quality and water standards, 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 each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain of Mississippi Power's former 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 of Mississippi Power's former officers made materially false and misleading statements regarding the Kemper IGCC 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. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.
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 of Mississippi Power's former officers. The complaint alleges that the defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC 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. Southern Company believes that this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power'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. Georgia Power has filed a petition for writ of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
certiorari with the Georgia Supreme Court. Georgia Power 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.
Southern Company Gas
Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in 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 Southern Company Gas' 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 Southern Company's or Southern Company Gas' financial statements.
Environmental Remediation
The Southern Company system 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 Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company Gas'the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have each 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Georgia Power's environmental remediation liability as of September 30, 2016March 31, 2017 was $23$13 million. 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. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the 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, including costs associated with implementation of the consent decree. Assessment and potential cleanup of othersuch sites are anticipated.
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 or Georgia Power's financial statements.is expected.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46$52 million as of September 30, 2016.March 31, 2017. 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.
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company and Gulf Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Southern Company Gas' environmental remediation liability as of September 30, 2016March 31, 2017 was $433$409 million 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 Southern Company Gas'the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.
The ultimatefinal outcome of these matters cannot be determined at this time; however, these matters are not expected to have a material impact on Southern Company's financial statements.
In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however,time. However, the final disposition of this matterthese matters is not expected to have a material impact on the financial statements of Southern Company's financial statements.Company, Georgia Power, Gulf Power, or Southern Company Gas.
FERC Matters
Municipal and Rural Associations Tariff
See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for additional information regarding Mississippi Power's construction of the Kemper IGCC.
OnIn March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers, and filed a request withwhich was subsequently approved by the FERC, for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA)MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
in November 2015. The settlement agreement accepted by the FERC,became effective for services rendered beginning May 1, 2016, provides that base ratesresulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million.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 underthrough an order issued by the December 2015 Mississippi PSC order authorizing rates providing recovery of assets previously placed in serviceDecember 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $11$18 million throughuntil the end of May 2017 when the Kemper IGCC'sIGCC is projected in-service date of December 31, 2016.to be placed in service.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2016,March 31, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $17$12 million compared to $24$13 million at December 31, 2015.2016. At September 30, 2016March 31, 2017 and December 31, 2015,2016, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million. 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.
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
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 April 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 in May 2015 and in June 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 February 23, 2017, the traditional electric operating companies and Southern Power accepted the terms of the order in a compliance filing. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.
The ultimate outcome of this matterthese matters cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Retail Regulatory Matters
Alabama Power
See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory"Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
| | | Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 | Balance Sheet Line Item | March 31,
2017 | December 31, 2016 |
|
| (in millions) |
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | — |
| $ | 43 |
| |
| | Deferred over recovered regulatory clause revenues | 23 |
| — |
| |
Rate CNP Compliance(*) | | Deferred under recovered regulatory clause revenues | $ | — |
| $ | 9 |
|
| Rate CNP PPA | Under recovered regulatory clause revenues | 52 |
| 99 |
| Over recovered regulatory clause revenues | 3 |
| — |
|
| | Deferred under recovered regulatory clause revenues | 87 |
| — |
| Deferred under recovered regulatory clause revenues | — |
| 142 |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | — |
| 238 |
| Other regulatory liabilities, current | 40 |
| 76 |
|
| Deferred over recovered regulatory clause revenues | 134 |
| — |
| |
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 71 |
| 75 |
| Other regulatory liabilities, deferred | 66 |
| 69 |
|
Environmental Accounting Order
In April 2016, as part of its environmental compliance strategy, Alabama Power 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 an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified the $23 million under recovered balance for Rate CNP Compliance to a deferred regulatory asset account. |
Georgia Power
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.
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 tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing 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 "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
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 on April 14, 2016, Georgia Power's 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 (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement;
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).Plan.
On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.
Additionally,March 7, 2017, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures takendecision 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 will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.
The Georgia PSC also approved the Renewable Energy Development Initiative 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.
The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear optionsuspend work at a future generation site in Stewart County, Georgia.Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
of cost recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.
As of September 30, 2016March 31, 2017 and December 31, 2015,2016, Georgia Power's over recovered fuel balance totaled $125$18 million and $116$84 million, respectively. For September 30, 2016, the balancerespectively, and is included in over recovered regulatory clause revenues, current on Georgia Power's Condensed Balance Sheets and in other current liabilities on Southern Company's Condensed Balance Sheets. For December 31, 2015, the balance is included in over recovered regulatory clause revenues, current and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheets and in other current liabilities and other deferred credits and liabilities on Southern Company's Condensed Balance Sheets. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
condensed balance sheets.
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 or Georgia Power's revenues or net income, but will affect cash flow.
Storm Damage Recovery
As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's 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 or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory"Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).
Vogtle 3 and 4 Agreement and Contractor Bankruptcy
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to a cap.an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of certaina credit rating downgradesdowngrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual 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 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) 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 accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent.
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 litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent forAmong other things, 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) reviserevised 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(ii) provided that delay liquidated damages will commence fromif the current estimated nuclear fuel loading date for each unit which isdoes not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide(iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of which approximately $256 million had been paid as of September 30, 2016. 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.disputed claims. Further, as parta consequence of the settlement and Westinghouse's acquisition of WECTEC: (i)WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia PSCPower's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has approved fourteen VCM reports coveringguaranteed certain payment obligations of the periodsContractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through December 31, 2015, including construction capital costs incurred, which through that date totaled $3.3 billion. On January 21, 2016,June 30, 2020 and require 60 days' written notice to Georgia Power submittedin the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor Settlementand WECTEC Staffing Services LLC (WECTEC Staffing), as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related amendmentto Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's and Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC for its review. In accordancevoted to certify construction of Plant Vogtle Units 3 and 4 with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information 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-servicea certified capital cost and schedule are reasonable.
On October 20, 2016, Georgia Power andof $4.418 billion. In addition, in 2009 the Georgia PSC Staff entered intoapproved 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 including the related CWIP accounts in rate base during the construction period.
On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through commercial operation.the date each unit is placed in service. The ROE used to calculate the NCCR tariff will bewas reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not commercially operationalplaced in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operationare placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.
Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or upon reaching commercial operation,when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.
The Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).
On August 31, 2016,that date totaled $3.7 billion. Georgia Power filed the fifteenthits sixteenth VCM report, with the Georgia PSC covering the period from JanuaryJuly 1 through June 30,December 31, 2016, requesting approval of $141$222 million of construction capital costs incurred during that period.period, with the Georgia PSC on February 27, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.8approximately $4.1 billion as of September 30, 2016. EstimatedMarch 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs during the construction period total approximately $2.4 billion,through March 31, 2017.
The ultimate outcome of which $1.2 billion had been incurred through September 30, 2016.these matters cannot be determined at this time.
Other Matters
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On November 1, 2016,March 31, 2017, Georgia Power submitted its 2017 NCCR tariff filing requestinghad borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through a loan guarantee agreement between Georgia Power and the DOE and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the current NCCR tariff rate remain effective for 2017 if theapplicable unit be placed in service prior to 2021. The net present value of Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase ofPower's PTCs is estimated at approximately $70 million.$400 million per unit.
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. 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
compliance matters, 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 labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressureGeorgia Power's previously estimated owner's costs of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2$10 million per month netand financing costs of delay liquidated damages and certain incentive payments that would no longer be required to be paidapproximately $30 million per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each ofmonth for 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 behalfare being evaluated as part of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formalcomprehensive schedule and informal dispute resolution procedures undercost-to-complete analysis being performed as a result of 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.Contractor's bankruptcy.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.
Retail Base Rate Cases
See Note 3 to the financial statements of Southern Company and Gulf Power under "Retail Regulatory"Regulatory Matters – Gulf Power – Retail Base Rate Case"Cases" and "Retail Regulatory Matters – Retail Base Rate Case,Cases," respectively, in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In 2013, the Florida PSC approved a settlement agreement (2013 Rate Case Settlement Agreement) 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 may not 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 the thirdfirst quarter 20162017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.
On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and in accordancethree of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the 2013terms of the 2017 Rate Case Settlement Agreement, Gulf Power reversed reductions previouslywill, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) begin 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 (4) implement 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 to depreciation. As a result, forin the first nine monthsquarter 2017. The remaining issues related to the inclusion of 2016, the net reductionGulf Power's investment in depreciation was zero.
On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increasePlant Scherer Unit 3 in retail rates and chargeshave been resolved as a result of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. TheRate Case Settlement Agreement, including recoverability of thecertain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case inunit through the second quarter 2017. Gulf Power has requested that the increase in base rates, ifenvironmental cost recovery clause rate approved by the Florida PSC become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.November 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:
| | | Regulatory Clause | Balance Sheet Line Item | September 30,
2016 | December 31, 2015 | Balance Sheet Line Item | March 31,
2017 | December 31, 2016 |
|
| (in millions) |
| (in millions) |
| Fuel Cost Recovery | Other regulatory liabilities, current | $ | 20 |
| $ | 18 |
| Other regulatory liabilities, current | $ | 5 |
| $ | 15 |
|
| Purchased Power Capacity Recovery | Other regulatory liabilities, current | 3 |
| — |
| Under recovered regulatory clause revenues | 4 |
| — |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | — |
| 1 |
| |
| Environmental Cost Recovery | Other regulatory liabilities, current | 5 |
| — |
| |
| Environmental Cost Recovery | Under recovered regulatory clause revenues | — |
| 19 |
| Under recovered regulatory clause revenues | 40 |
| 13 |
|
| Energy Conservation Cost Recovery | Other regulatory liabilities, current | — |
| 4 |
| Under recovered regulatory clause revenues | 3 |
| 4 |
|
| Energy Conservation Cost Recovery | Under recovered regulatory clause revenues | 2 |
| — |
| |
On November 2, 2016,As discussed previously, the Florida PSC approved2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effectinclusion of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs and the related impact on rates is expected to be decidedapproved by the Florida PSC in theNovember 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.
Other Matters
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) on March 31, 2016. Gulf Power filed a petition with the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Florida PSC requesting permission to recover 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. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.was made.
Mississippi Power
Energy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.
On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.
Performance Evaluation Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.
On April 1, 2016,March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2015,2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.
On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.
The ultimate outcome of these mattersthis matter cannot be determined at this time.
Environmental Compliance Overview PlanEnergy Efficiency
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan"Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ECO Plan.energy efficiency programs.
In November 2016, Mississippi Power submitted its Energy Efficiency Cost Rider (EECR) Compliance filing, which included an increase of $1 million in annual retail revenues. On August 17, 2016,March 13, 2017, Mississippi Power amended and revised the Mississippi PSC approved Mississippi Power's revised ECO PlanEECR Compliance filing for 2016, which requested the maximum 2%to request a $2 million annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015.retail revenues. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 millionultimate outcome of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.this matter cannot be determined at this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.
At September 30, 2016,March 31, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheetcondensed balance sheet was $58$27 million compared to $71$37 million at December 31, 2015.
The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Ad Valorem Tax Adjustment
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.
On April 7, 2017, Mississippi Power submitted its 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. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flow.flows.
Regulatory Infrastructure ProgramsBase Rate Cases
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 update or expandSee Note 3 to the natural gas distribution systemsfinancial statements of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern Company Gas currently hasunder "Regulatory Matters – Base Rate Cases" in Item 8 of the Form 10-K for additional information.
On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (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, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure improvement programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program, Integrated System Reinforcement Program, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in six different states with initial program lengths ranging from four to 10 years,annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.
Beginning with the longest setnext 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 Georgia PSC allowed the last monthly Pipeline Replacement Program surcharge increase, originally scheduled for October 2017, to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.occur effective March 1, 2017.
Southern CompanyIn September 2016, Elizabethtown Gas currently has proposed infrastructure improvement programs pending approval byfiled a general base rate case with the applicable state regulatory agencies in Georgia and New Jersey BPU requesting averagea $19 million increase in annual spendingbase rate revenues. The requested increase is based on a projected 12-month test year ending March 31, 2017 and an ROE of 10.25%. The New Jersey BPU is expected to issue an order on the filing in the third quarter 2017, after which rate adjustments will be effective.
On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and an ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.
On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million through 2020increase in annual base rate revenues. The requested increase is based on a projected 12-month test year beginning September 1, 2017 and $110an ROE of 10.25%. The requested increase includes $13 million through 2027, respectively. related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. The Virginia Commission is expected to rule on the requested increase in the first quarter 2018. Rate adjustments are expected to be effective September 1, 2017, subject to refund.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The ultimate outcome of these mattersthe pending base rate cases cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.
Nicor Gas
In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $24 million of qualifying assets during the first quarter 2017.
Atlanta Gas Light
Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and liquefied natural gas facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $38 million during the first quarter 2017.
In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (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 recovery of and return on current and future capital investments under the STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM that was approved by the Georgia PSC on February 21, 2017. See "Base Rate Cases" herein for additional information.
Elizabethtown Gas
In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $3 million during the first quarter 2017.
Virginia Natural Gas
In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $7 million during the first quarter 2017.
Florida City Gas
The Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program in 2015. Under the program, Florida City Gas invested $3 million during the first quarter 2017.
Integrated Coal Gasification Combined Cycle
See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.
Kemper IGCC Overview
The Kemper IGCC will utilize anutilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC will beis fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, 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. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $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 (Initial 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 in August 2014 and continues to progress towards completing the2014. The remainder of the Kemper IGCC,plant, including the gasifiers and the gas clean-up facilities.facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016,Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the Kemper IGCC began testing using cleanproduction of electricity from syngas from gasifier "A"in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO2, and has produced sulfuric acid and ammonia, all of acceptable quality under the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experiencedoff-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and on November 2, 2016,reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power determined a maintenance outage on gasifier "A" iscurrently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017. The schedule reflects the expected time needed to repair a leak in one of the particulate control devices for gasifier "A," make improvementsother minor modifications to theeach gasifier's ash removal systems.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date for the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
Recovery of the costs subject to the 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 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) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2016March 31, 2017, all of which include 100% of the costs for the Kemper IGCC, are as follows:
| | | Cost Category | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(c)(e) | $ | 2.40 |
| | $ | 5.52 |
| | $ | 5.30 |
| $ | 2.40 |
| | $ | 5.75 |
| | $ | 5.57 |
|
| Lignite Mine and Equipment | 0.21 |
| | 0.23 |
| | 0.23 |
| 0.21 |
| | 0.23 |
| | 0.23 |
|
CO2 Pipeline Facilities | 0.14 |
| | 0.11 |
| | 0.11 |
| 0.14 |
| | 0.12 |
| | 0.12 |
|
AFUDC(d) | 0.17 |
| | 0.75 |
| | 0.71 |
| 0.17 |
| | 0.83 |
| | 0.80 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | — |
| | 0.04 |
| | 0.03 |
| — |
| | 0.05 |
| | 0.04 |
|
| General Exceptions | 0.05 |
| | 0.10 |
| | 0.09 |
| 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(e) | — |
| | 0.21 |
| | 0.20 |
| — |
| | 0.22 |
| | 0.22 |
|
Additional DOE Grants(f) | — |
| | (0.14 | ) | | (0.14 | ) | — |
| | (0.14 | ) | | (0.14 | ) |
Total Kemper IGCC | $ | 2.97 |
| | $ | 6.82 |
| | $ | 6.53 |
| $ | 2.97 |
| | $ | 7.16 |
| | $ | 6.93 |
|
| |
| (a) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions. |
| |
| (b) | Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap. |
| |
| (c) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Costcost 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.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 (e) for additional information. |
| |
| (d) | Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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. |
| |
| (e) | Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016.March 31, 2017. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016.March 31, 2017. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information. |
| |
| (f) | On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (g) | The Current Cost Estimate and the Actual Costs include $2.87 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.09 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.23 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 and Note 6 to the financial statements of Mississippi Power under "Fuel Inventory" and "Capital Leases," respectively, in Item 8 of the Form 10-K and "Rate Recovery of Kemper IGCC Costs – 2017 Rate Case" herein for additional information. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70March 31, 2017, $3.73 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.63$2.95 billion), $6 million in other property and investments, $81$64 million in fossil fuel stock, $46$48 million in materials and supplies, $33$24 million in other regulatory assets, current, $177$173 million in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
other regulatory assets, deferred, $4$1 million in other current assets, and $9$17 million in other deferred charges and assets in the balance sheet.
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 Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $88$108 million ($5467 million after tax) in the thirdfirst quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016.2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63$2.87 billion ($1.631.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.March 31, 2017. The increase to the cost estimate in the thirdfirst quarter of 20162017 primarily reflects $53$67 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016mid-March 2017 to December 31, 2016 and increased effortsthe end of May 2017, $23 million related to start-up fuel, and $18 million primarily related to outage maintenance and operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subjectimprovements.
In addition to the cost cap. The year-to-date increase to thecurrent construction cost estimate, also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. TheApproximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.
Any extension of the in-service date beyond DecemberMay 31, 20162017 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, additionalAdditional 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 DecemberMay 31, 20162017 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 $15$16 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 $3 million per month. For additional information, see "Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein.
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. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Rate Recovery of Kemper IGCC Costs
See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recoveryGiven the variety of a portionpotential scenarios and the uncertainty of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recoveryoutcome of the retail portion of the Kemper IGCC is subject to the jurisdiction offuture regulatory proceedings with the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax informationPSC (and any subsequent related tolegal challenges), 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 now be determined at this time, but could result in further material charges that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relatingNOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of March 31, 2017, in addition to boththe $2.87 billion of costs above the Mississippi Power's recovery of financingPSC's $2.88 billion cost cap that have been recognized as a charge to income, Mississippi Power had incurred approximately $2.01 billion in costs duringsubject to the course ofcost cap and approximately $1.50 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current rates. These costs primarily relate to the following: |
| | | |
| Cost Category | Actual Costs |
| | (in billions) |
| Gasifiers and Gas Clean-up Facilities | $ | 1.90 |
|
| Lignite Mine Facility | 0.31 |
|
CO2 Pipeline Facilities | 0.11 |
|
| Combined Cycle and Common Facilities | 0.17 |
|
| AFUDC | 0.73 |
|
| General exceptions | 0.07 |
|
| Plant inventory | 0.04 |
|
| Lignite inventory | 0.06 |
|
| Regulatory and other deferred assets | 0.12 |
|
| Subtotal | 3.51 |
|
| Additional DOE Grants | (0.14 | ) |
| Total | $ | 3.37 |
|
Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. Mississippi Power's recoveryPower and its wholesale customers have generally agreed to similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of costs followingProposed Sale of Undivided Interest" herein for further information.
Prudence
On August 17, 2016, the dateMississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC is placed in service. With respectCompared to recoveryamounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs followingexpected to be required to support the in-service dateoperations of the Kemper IGCC during that period. Mississippi Power will not seek recovery of the 2012 MPSC CPCN Order provided$68 million in additional estimated costs from customers if incurred.
Mississippi Power responded to numerous requests for information from interested parties in the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN.discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to apply operational parametersaddress these matters in connection with future proceedings related to the operation2017 Rate Case.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Economic Viability Analysis
In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected.
As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. ToThe project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.
Mississippi Power expects the Mississippi PSC determinesto address this matter in connection with the 2017 Rate Case.
2017 Rate Case
Mississippi Power continues to believe that all costs related to the Kemper IGCC doesthat remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under "Prudence," "Lignite Mine and CO2 Pipeline Facilities," "Termination of Proposed Sale of Undivided Interest," and "Income Tax Matters," these challenges include, but are not meetlimited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the operational parameters ultimately adopted by15% portion of the project previously contracted to SMEPA.
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 utilize this legislation 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.
After the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. In connection with the 2017 Rate Case, Mississippi Power expects to file a request for authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event the Mississippi PSC does not grant Mississippi Power's request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates.
Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power incurs additionalis developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to satisfybe filed by June 3, 2017. Mississippi
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such parameters, there could be a material adverse impactan agreement on Southern Company's orand Mississippi Power's financial statements.statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) 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. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation (2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. 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. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Prudence""Termination of Proposed Sale of Undivided Interest" herein for additional information. Mississippi Power is required to file the 2017 Rate Case by June 3, 2017.
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
2013 MPSC Rate Order
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, based on a mirror CWIP methodology (Mirror CWIP rate).
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. Through September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
On February 12, 2015, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.above.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2015 Rate Case
On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) 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. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle for September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. 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. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.
On July 27, 2016, the Court dismissed Greenleaf CO2 Solutions, LLC (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.
In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and the FERC to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.
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 regardingBecause the 2013 MPSC Rate Order did not impactprovide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through March 31, 2017, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $445 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.
2012 MPSC CPCN Order
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's ability to utilize alternaterecovery of financing through securitization orcosts during the February 2013 legislation.
Prudence
On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudencecourse of construction of the Kemper IGCC. On October 3, 2016,IGCC and Mississippi Power made a required compliance filing, which included a review and explanationPower's recovery of differences betweencosts following the date the Kemper IGCC project estimate set forthis placed in service. With respect to recovery of costs following the 2010 CPCN proceeding andin-service date of the most recent Kemper IGCC, project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 20102012 MPSC CPCN proceedingsOrder provided for the first five years following the startestablishment of commercial operations. Certain costs,operational cost and revenue parameters including
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
operations availability factor, heat rate, lignite heat content, and maintenance, are materially higher than the amounts presentedchemical revenue based upon assumptions in the CPCN proceedings. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up periodMississippi Power's petition for the current estimates reflects a lower starting point and a slower escalation rate.CPCN. Mississippi Power expects the Mississippi PSC to address these issuesapply operational parameters in connection with its next rate request.the 2017 Rate Case and 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 be a material adverse impact on Southern Company's or Mississippi Power's financial statements. See "Prudence" herein for additional information.
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 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, 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 amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2016,March 31, 2017, the balance associated with these regulatory assets was $105$86 million, of which $33$24 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105$111 million as of September 30, 2016.March 31, 2017. The amortization period for 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.2017 Rate Case. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.
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. At September 30, 2016,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
March 31, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7$8 million. See "2015 Rate Case" herein for additional information.
See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.
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 IGCC 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 operating and managing the mining operations. The contract with Liberty Fuels is effective 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. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO2 captured from the Kemper IGCC and Treetop would purchase 30% of the CO2 captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO2 captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and 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 or otherwise sequester the CO2 produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally 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 cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest
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 (15% Undivided Interest). On May 20, 2015, SMEPA notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest. 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 July 31, 2018.
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. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
District of Mississippi, where the case is currently pending. However, theMississippi. The plaintiffs have filed a request to remand the case back to state court.court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, 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 IGCC 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 IGCC; 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 IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and Mississippi Power filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.
On June 9, 2016, Treetop, 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 relates to the cancelled CO2 contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO2 contract.contract, which the court is expected to address in the second quarter 2017.
Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Baseload Act
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. See "Rate Recovery of Kemper IGCC Costs" herein for additional information. Income Tax Matters
TableSee Note 3 to the financial statements of ContentsSouthern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (C) | FAIR VALUE MEASUREMENTS |
As of September 30, 2016,March 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 September 30, 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) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 203 |
| | $ | 190 |
| | $ | — |
| | $ | — |
| | $ | 393 |
|
| Interest rate derivatives | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Nuclear decommissioning trusts(b) | 660 |
| | 938 |
| | — |
| | 18 |
| | 1,616 |
|
| Cash equivalents | 1,680 |
| | — |
| | — |
| | — |
| | 1,680 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 2,552 |
| | $ | 1,170 |
| | $ | 1 |
| | $ | 18 |
| | $ | 3,741 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | 267 |
| | $ | 274 |
| | $ | — |
| | $ | — |
| | $ | 541 |
|
| Interest rate derivatives | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Foreign currency derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
| Total | $ | 267 |
| | $ | 305 |
| | $ | 18 |
| | $ | — |
| | $ | 590 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
Nuclear decommissioning trusts(c) | | | | | | | | |
|
|
| Domestic equity | 373 |
| | 72 |
| | — |
| | — |
| | 445 |
|
| Foreign equity | 49 |
| | 49 |
| | — |
| | — |
| | 98 |
|
| U.S. Treasury and government agency securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Corporate bonds | 22 |
| | 148 |
| | — |
| | — |
| | 170 |
|
| Mortgage and asset backed securities | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
| Private Equity | — |
| | — |
| | — |
| | 18 |
| | 18 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 410 |
| | — |
| | — |
| | — |
| | 410 |
|
| Total | $ | 854 |
| | $ | 327 |
| | $ | — |
| | $ | 18 |
| | $ | 1,199 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of March 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) |
| Southern Company | | | | | | | | | |
| Assets: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 274 |
| | $ | 213 |
| | $ | — |
| | $ | — |
| | $ | 487 |
|
| Interest rate derivatives | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
Nuclear decommissioning trusts(c) | 714 |
| | 942 |
| | — |
| | 21 |
| | 1,677 |
|
| Cash equivalents | 589 |
| | — |
| | — |
| | — |
| | 589 |
|
| Other investments | 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | $ | 1,586 |
| | $ | 1,168 |
| | $ | 1 |
| | $ | 21 |
| | $ | 2,776 |
|
| Liabilities: | | | | | | | | | |
Energy-related derivatives(a)(b) | $ | 303 |
| | $ | 155 |
| | $ | — |
| | $ | — |
| | $ | 458 |
|
| Interest rate derivatives | — |
| | 32 |
| | — |
| | — |
| | 32 |
|
| Foreign currency derivatives | — |
| | 62 |
| | — |
| | — |
| | 62 |
|
| Contingent consideration | — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | 303 |
| | $ | 249 |
| | $ | 20 |
| | $ | — |
| | $ | 572 |
|
| | | | | | | | | | |
| Alabama Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
Nuclear decommissioning trusts:(d) | | | | | | | | |
|
|
| Domestic equity | 405 |
| | 77 |
| | — |
| | — |
| | 482 |
|
| Foreign equity | 52 |
| | 51 |
| | — |
| | — |
| | 103 |
|
| U.S. Treasury and government agency securities | — |
| | 28 |
| | — |
| | — |
| | 28 |
|
| Corporate bonds | 22 |
| | 143 |
| | — |
| | — |
| | 165 |
|
| Mortgage and asset backed securities | — |
| | 18 |
| | — |
| | — |
| | 18 |
|
| Private Equity | — |
| | — |
| | — |
| | 21 |
| | 21 |
|
| Other | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Cash equivalents | 555 |
| | — |
| | — |
| | — |
| | 555 |
|
| Total | $ | 1,034 |
| | $ | 335 |
| | $ | — |
| | $ | 21 |
| | $ | 1,390 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of September 30, 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) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Interest rate derivatives | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Nuclear decommissioning trusts(c) (d) | | | | | | | | | |
| Domestic equity | 197 |
| | 1 |
| | — |
| | — |
| | 198 |
|
| Foreign equity | — |
| | 125 |
| | — |
| |
|
| | 125 |
|
| U.S. Treasury and government agency securities | — |
| | 59 |
| | — |
| | — |
| | 59 |
|
| Municipal bonds | — |
| | 70 |
| | — |
| | — |
| | 70 |
|
| Corporate bonds | — |
| | 172 |
| | — |
| | — |
| | 172 |
|
| Mortgage and asset backed securities | — |
| | 149 |
| | — |
| | — |
| | 149 |
|
| Other | 19 |
| | 43 |
| | — |
| | — |
| | 62 |
|
| Cash equivalents | 32 |
| | — |
| | — |
| | — |
| | 32 |
|
| Total | $ | 248 |
| | $ | 644 |
| | $ | — |
| | $ | — |
| | $ | 892 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Total | $ | 20 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 51 |
| | $ | — |
| | $ | — |
| | $ | 51 |
|
| Interest rate derivatives | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
| Total | $ | — |
| | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | 137 |
| | — |
| | — |
| | — |
| | 137 |
|
| Total | $ | 137 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 138 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 21 |
|
| Interest rate derivatives | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Total | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | | |
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using: | | |
| As of March 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) |
| Georgia Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | 24 |
|
| Interest rate derivatives | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Nuclear decommissioning trusts:(d) (e) | | | | | | | | | |
| Domestic equity | 216 |
| | 1 |
| | — |
| | — |
| | 217 |
|
| Foreign equity | — |
| | 137 |
| | — |
| | — |
| | 137 |
|
| U.S. Treasury and government agency securities | — |
| | 196 |
| | — |
| | — |
| | 196 |
|
| Municipal bonds | — |
| | 70 |
| | — |
| | — |
| | 70 |
|
| Corporate bonds | — |
| | 168 |
| | — |
| | — |
| | 168 |
|
| Mortgage and asset backed securities | — |
| | 41 |
| | — |
| | — |
| | 41 |
|
| Other | 19 |
| | 5 |
| | — |
| | — |
| | 24 |
|
| Cash equivalents | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | $ | 235 |
| | $ | 644 |
| | $ | — |
| | $ | — |
| | $ | 879 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
|
| Interest rate derivatives | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| Total | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | — |
| | $ | 17 |
|
| | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Cash equivalents | 21 |
| | — |
| | — |
| | — |
| | 21 |
|
| Total | $ | 21 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | 31 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
| Total | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 12 |
|
| | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | Fair Value Measurements Using | | | Fair Value Measurements Using: | | |
| As of September 30, 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 | |
| As of March 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) | (in millions) |
| Southern Power | | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Foreign currency derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
| |
| Cash equivalents | 647 |
| | — |
| | — |
| | — |
| | 647 |
| |
| Total | $ | 647 |
| | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | 673 |
| |
| Liabilities: | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Foreign currency derivatives | — |
| | 24 |
| | — |
| | — |
| | 24 |
| — |
| | 62 |
| | — |
| | — |
| | 62 |
|
| Contingent consideration | — |
| | — |
| | 18 |
| | — |
| | 18 |
| — |
| | — |
| | 20 |
| | — |
| | 20 |
|
| Total | $ | — |
|
| $ | 27 |
|
| $ | 18 |
|
| $ | — |
|
| $ | 45 |
| $ | — |
|
| $ | 67 |
|
| $ | 20 |
|
| $ | — |
|
| $ | 87 |
|
| | | | | | | | | | | |
| Southern Company Gas | | | | | | | | | | |
| Assets: | | | | | | | | | | |
Energy-related derivatives(a)(b) | | $ | 274 |
| | $ | 158 |
| | $ | — |
| | $ | — |
| | $ | 432 |
|
| Liabilities: | | | | | | | | | | |
Energy-related derivatives(a)(b) | | $ | 303 |
| | $ | 84 |
| | $ | — |
| | $ | — |
| | $ | 387 |
|
| |
| (a) | Excludes $7$19 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value. |
| |
| (b) | Excludes cash collateral of $92 million. |
| |
| (c) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
(c)(d) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
| |
(d)(e) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2016,March 31, 2017, approximately $42$56 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. |
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $49$63 million and $116$20 million respectively, for the three and nine months ended September 30,March 31, 2017 and 2016, and decreased by $65 million and $33 million, respectively, for the three and nine months ended September 30, 2015.respectively. Alabama Power recorded an increase in fair value of $26$34 million and $66$11 million respectively, for the three and nine months ended September 30,March 31, 2017 and 2016, and a decrease in fair value of $39 million and $19 million, respectively, for the three and nine months ended September 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded an increase in fair value of $23$29 million and $50$9 million respectively, for the three and nine months ended September 30,March 31, 2017 and 2016, and a decrease in fair value of $26 million and $14 million, respectively, for the three and nine months ended September 30, 2015 as a change in its regulatory asset related to its AROs.
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 (H) 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 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to pay generation-based payments to the seller over a 10-year period ranging from 10 to 30 years, beginning at the commercial operation date. The obligation is measured atcategorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs such asfor 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 have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of September 30, 2016,March 31, 2017, 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:
| | | As of September 30, 2016: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period | |
| As of March 31, 2017: | | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | (in millions) | |
| Southern Company | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable | $ | 21 |
| | $ | 22 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 18 |
| | $ | 27 |
| | Not Applicable | | Not Applicable | $ | 21 |
| | $ | 22 |
| | 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 fund that invests 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of September 30, 2016,March 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value |
| | (in millions) | (in millions) |
| Long-term debt, including securities due within one year: | | | | | | |
| Southern Company | $ | 43,668 |
| | $ | 47,227 |
| $ | 45,881 |
| | $ | 46,828 |
|
| Alabama Power | $ | 7,091 |
| | $ | 7,961 |
| $ | 7,439 |
| | $ | 7,807 |
|
| Georgia Power | $ | 10,398 |
| | $ | 11,582 |
| $ | 11,362 |
| | $ | 11,777 |
|
| Gulf Power | $ | 1,184 |
| | $ | 1,267 |
| $ | 1,079 |
| | $ | 1,110 |
|
| Mississippi Power | $ | 2,981 |
| | $ | 2,967 |
| $ | 2,977 |
| | $ | 2,909 |
|
| Southern Power | $ | 4,608 |
| | $ | 4,821 |
| $ | 5,648 |
| | $ | 5,694 |
|
| Southern Company Gas | | $ | 5,268 |
| | $ | 5,487 |
|
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 registrants.Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
Earnings per Share
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on 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 share were as follows:
| | | | Three Months Ended September 30, 2016 |
| Three Months Ended September 30, 2015 | | Nine Months Ended September 30, 2016 | | Nine Months Ended September 30, 2015 | Three Months Ended March 31, 2017 |
| Three Months Ended March 31, 2016 |
| | (in millions) | (in millions) |
| As reported shares | 968 |
| | 910 |
| | 940 |
| | 910 |
| 993 |
| | 916 |
|
| Effect of options and performance share award units | 7 |
| | 2 |
| | 5 |
| | 3 |
| 7 |
| | 6 |
|
| Diluted shares | 975 |
| | 912 |
| | 945 |
| | 913 |
| 1,000 |
| | 922 |
|
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three andnine months ended September 30, 2016March 31, 2017 and were 15 million and 1 million for the three and nine months ended September 30, 2015, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes in Stockholders' Equity
The following table presents year-to-date changes in stockholders' equity of Southern Company:
| | | | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | | Total
Stockholders'
Equity | Number of Common Shares | | Common
Stockholders'
Equity | Preferred and Preference Stock of Subsidiaries | | | Total
Stockholders'
Equity |
| | Issued | Treasury | | Noncontrolling Interests(*) | | Issued | Treasury | | Noncontrolling Interests(*) | |
| | | (in thousands) | | (in millions) |
| Balance at December 31, 2016 | | 991,213 |
| (819 | ) | | $ | 24,758 |
| $ | 609 |
| $ | 1,245 |
| | $ | 26,612 |
|
| Consolidated net income attributable to Southern Company | | — |
| — |
| | 658 |
| — |
| — |
| | 658 |
|
| Other comprehensive income (loss) | | — |
| — |
| | (9 | ) | — |
| — |
| | (9 | ) |
| Stock issued | | 4,240 |
| — |
| | 186 |
| — |
| — |
| | 186 |
|
| Stock-based compensation | | — |
| — |
| | 57 |
| — |
| — |
| | 57 |
|
| Cash dividends on common stock | | — |
| — |
| | (556 | ) | — |
| — |
| | (556 | ) |
| Contributions from noncontrolling interests | | — |
| — |
| | — |
| — |
| 71 |
| | 71 |
|
| Distributions to noncontrolling interests | | — |
| — |
| | — |
| — |
| (18 | ) | | (18 | ) |
| Net income attributable to noncontrolling interests | | — |
| — |
| | — |
| — |
| (4 | ) | | (4 | ) |
| Other | | — |
| (35 | ) | | — |
| — |
| (1 | ) | | (1 | ) |
| Balance at March 31, 2017 | | 995,453 |
| (854 | ) | | $ | 25,094 |
| $ | 609 |
| $ | 1,293 |
| | $ | 26,996 |
|
| | (in thousands) | | (in millions) | | | | | |
| Balance at December 31, 2015 | 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| | $ | 21,982 |
| 915,073 |
| (3,352 | ) | | $ | 20,592 |
| $ | 609 |
| $ | 781 |
| | $ | 21,982 |
|
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,226 |
| — |
| — |
| | 2,226 |
| — |
| — |
| | 489 |
| — |
| — |
| | 489 |
|
| Other comprehensive income (loss) | — |
| — |
| | (95 | ) | — |
| — |
| | (95 | ) | — |
| — |
| | (114 | ) | — |
| — |
| | (114 | ) |
| Stock issued | 65,725 |
| 2,599 |
| | 3,265 |
| — |
| — |
| | 3,265 |
| 6,572 |
| — |
| | 270 |
| — |
| — |
| | 270 |
|
| Stock-based compensation | — |
| — |
| | 119 |
| — |
| — |
| | 119 |
| — |
| — |
| | 57 |
| — |
| — |
| | 57 |
|
| Cash dividends on common stock | — |
| — |
| | (1,553 | ) | — |
| — |
| | (1,553 | ) | — |
| — |
| | (497 | ) | — |
| — |
| | (497 | ) |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 357 |
| | 357 |
| — |
| — |
| | — |
| — |
| 129 |
| | 129 |
|
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (21 | ) | | (21 | ) | — |
| — |
| | — |
| — |
| (4 | ) | | (4 | ) |
| Purchase of membership interests from noncontrolling interests | — |
| — |
| | — |
| — |
| (129 | ) | | (129 | ) | — |
| — |
| | — |
| — |
| (129 | ) | | (129 | ) |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 36 |
| | 36 |
| — |
| — |
| | — |
| — |
| 1 |
| | 1 |
|
| Other | — |
| (46 | ) | | (7 | ) | — |
| — |
| | (7 | ) | — |
| (35 | ) | |
|
| — |
| — |
| | — |
|
| Balance at September 30, 2016 | 980,798 |
| (799 | ) | | $ | 24,547 |
| $ | 609 |
| $ | 1,024 |
| | $ | 26,180 |
| |
| | | | | | | |
| Balance at December 31, 2014 | 908,502 |
| (725 | ) | | $ | 19,949 |
| $ | 756 |
| $ | 221 |
| | $ | 20,926 |
| |
| Consolidated net income attributable to Southern Company | — |
| — |
| | 2,096 |
| — |
| — |
| | 2,096 |
| |
| Other comprehensive income (loss) | — |
| — |
| | (7 | ) | — |
| — |
| | (7 | ) | |
| Stock issued | 3,769 |
| — |
| | 136 |
| — |
| — |
| | 136 |
| |
| Stock-based compensation | — |
| — |
| | 78 |
| — |
| — |
| | 78 |
| |
| Stock repurchased, at cost | — |
| (2,599 | ) | | (115 | ) | — |
| — |
| | (115 | ) | |
| Cash dividends on common stock | — |
| — |
| | (1,465 | ) | — |
| — |
| | (1,465 | ) | |
| Preference stock redemption | — |
| — |
| | — |
| (150 | ) | — |
| | (150 | ) | |
| Contributions from noncontrolling interests | — |
| — |
| | — |
| — |
| 429 |
| | 429 |
| |
| Distributions to noncontrolling interests | — |
| — |
| | — |
| — |
| (13 | ) | | (13 | ) | |
| Net income attributable to noncontrolling interests | — |
| — |
| | — |
| — |
| 13 |
| | 13 |
| |
| Other | — |
| (8 | ) | | (8 | ) | 3 |
| — |
| | (5 | ) | |
| Balance at September 30, 2015 | 912,271 |
| (3,332 | ) | | $ | 20,664 |
| $ | 609 |
| $ | 650 |
| | $ | 21,923 |
| |
| Balance at March 31, 2016 | | 921,645 |
| (3,387 | ) | | $ | 20,797 |
| $ | 609 |
| $ | 778 |
| | $ | 22,184 |
|
| |
| (*) | Primarily relatedRelated to Southern Power Company and excludes redeemable noncontrolling interests. Subsequent to March 31, 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Going Concern
As of March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $1.2 billion primarily due to a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes that mature on November 15, 2017, as well as $36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, 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 contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K.
DOE Loan Guarantee Borrowings
See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's loan guarantee agreement (Loan Guarantee Agreement) with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.
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%.
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, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, 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. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement.
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 3 and 4 Agreement under certain circumstances; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iii) 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Under the FFB 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 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.
See Note (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2016March 31, 2017 was approximately $1.9 billion (comprised of approximately $890 million at Alabama Power, $868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at September 30, 2016,March 31, 2017, the traditional electric operating companies had approximately $358$386 million (comprised of approximately $87 million at Alabama Power, $250 million at Georgia Power, and $21$86 million at Gulf Power, and $50 million at Mississippi Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of September 30, 2016:March 31, 2017:
| | | | 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 | 2017 | 2018 | 2020 | | 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 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | — |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
| 35 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | 50 |
| 65 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
| 85 |
| 195 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 25 |
| | 70 |
|
| Mississippi Power | 100 |
| 75 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
| 173 |
| — |
| — |
| | 173 |
| | 141 |
| | — |
| | 13 |
| | 13 |
| | 160 |
|
Southern Power Company(b) | — |
| — |
| — |
| 600 |
| | 600 |
| | 532 |
| | — |
| | — |
| | — |
| | — |
| — |
| — |
| 600 |
| | 600 |
| | 524 |
| | — |
| | — |
| | — |
| | — |
|
Southern Company Gas(c)(b) | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,947 |
| | — |
| | — |
| | — |
| | — |
| 75 |
| 1,925 |
| — |
| | 2,000 |
| | 1,949 |
| | — |
| | — |
| | — |
| | 75 |
|
| Other | — |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
| 55 |
| — |
| — |
| | 55 |
| | 55 |
| | 20 |
| | — |
| | 20 |
| | 35 |
|
| Southern Company Consolidated | $ | 150 |
| $ | 305 |
| $ | 3,590 |
| $ | 4,400 |
| | $ | 8,445 |
| | $ | 8,281 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 300 |
| $ | 423 |
| $ | 3,620 |
| $ | 4,400 |
| | $ | 8,443 |
| | $ | 8,266 |
| | $ | 65 |
| | $ | 13 |
| | $ | 58 |
| | $ | 375 |
|
| |
| (a) | Represents the Southern Company parent entity. |
| |
| (b) | Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.
|
| |
(c) | Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3$1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700$700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. |
On May 24, 2016, Southern Company's $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.
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 Power Project Credit Facilities
In connection with the construction of solar facilities by RE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (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 is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
solar facilities. 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 September 30, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Total Loan Facility | | Loan Facility Undrawn | | Letter of Credit Facility | | Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Garland | | Earlier of PPA COD or November 30, 2016 | | $ | 86 |
| | $ | 308 |
| | $ | 394 |
| | $ | 21 |
| | $ | 49 |
| | $ | 23 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016(*) | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Tranquillity | | October 14, 2016 | | 86 |
| | 172 |
| | 258 |
| | 12 |
| | 77 |
| | 26 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 67 |
| | $ | 149 |
| | $ | 65 |
|
| |
(*) | Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016. |
The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.
Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this 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 2.21%.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first ninethree months of 2016:2017:
| | Company | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Revenue
Bond
Maturities Redemptions and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(a) | Senior Note Issuances | | Senior Note Maturities and Redemptions | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(b) |
| | (in millions) | (in millions) |
Southern Company(b)(c) | $ | 8,500 |
| | $ | 500 |
| | $ | — |
| | $ | 800 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | 400 |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
| 550 |
| | 200 |
| | — |
| | — |
|
| Georgia Power | 650 |
| | 700 |
| | 4 |
| | 300 |
| | 5 |
| 850 |
| | — |
| | — |
| | 2 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | 2 |
| | — |
| — |
| | — |
| | 6 |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 652 |
| |
| Southern Power | 1,531 |
| | — |
| | — |
| | 63 |
| | 84 |
| — |
| | — |
| | 3 |
| | 2 |
|
Southern Company Gas(c) | 900 |
| | 300 |
| | — |
| | — |
| | — |
| |
| Other | — |
| | — |
| | — |
| | — |
| | 60 |
| — |
| | — |
| | — |
| | 4 |
|
Elimination(d) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) | |
| Southern Company Consolidated | $ | 11,981 |
| | $ | 1,825 |
| | $ | 4 |
| | $ | 2,110 |
| | $ | 576 |
| $ | 1,400 |
| | $ | 200 |
| | $ | 9 |
| | $ | 408 |
|
| |
| (a) | Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017. |
| |
| (b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
(b)(c) | Represents the Southern Company parent entity. |
| |
(c) | Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas. |
| |
(d) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
Southern Company
In May 2016,March 2017, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:repaid at maturity a $400 million 18-month floating rate bank loan.
$0.5 billion of 1.55% Senior Notes due July 1, 2018;
$1.0 billion of 1.85% Senior Notes due July 1, 2019;
$1.5 billion of 2.35% Senior Notes due July 1, 2021;
$1.25 billion of 2.95% Senior Notes due July 1, 2023;
$1.75 billion of 3.25% Senior Notes due July 1, 2026;
$0.5 billion of 4.25% Senior Notes due July 1, 2036; and
$2.0 billion of 4.40% Senior Notes due July 1, 2046.
The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes.Alabama Power
In September 2016, Southern CompanyMarch 2017, Alabama Power issued $800$550 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated2017A 2.45% Senior Notes due October 1, 2076.March 30, 2022. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Alabama Power
In January 2016, 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 maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.
In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.
Georgia Power
In March 2016,2017, Georgia Power issued $325$450 million aggregate principal amount of Series 2016A 3.25%2017A 2.00% Senior Notes due April 1, 2026March 30, 2020 and $325$400 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A2017B 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities.March 30, 2027. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.
In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.
Gulf Power
In May 2016,March 2017, Gulf Power redeemed $125extended the maturity of a $100 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.
Also in May 2016, Gulf Power entered into an 11-monthshort-term floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were usedLIBOR from April 2017 to repay existing indebtedness and for working capital and other general corporate purposes.October 2017.
Mississippi Power
On JanuaryFebruary 28, 2016,2017, Mississippi Power issued a promissory note for up to $275amended $551 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.extending the maturity dates of the notes from December 1, 2017 to July 31, 2018.
In June 2016,On March 31, 2017, Mississippi Power renewedissued a $10$9 million short-term note which matures on June 30, 2017, bearing interest basedat 5% per annum, which was repaid on three-month LIBOR.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power
In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) under "Foreign Currency Derivatives" for additional information.
In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.
Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.
In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.
During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.
Southern Company Gas
In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees.employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended.amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2016.2017. 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.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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. TheThis qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Employee Retirement Income Security Act of 1974, as amended. Southern Company Gas made a $125 million voluntary contribution to the qualified pension plan in September 2016.are anticipated for the year ending December 31, 2017. 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 largely unfunded and benefits are primarily paid using corporate assets.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.
See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.
Components of the net periodic benefit costs for the three and nine months ended September 30,March 31, 2017 and 2016 and 2015 were as follows:are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 68 |
| | $ | 14 |
| | $ | 17 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 110 |
| | 23 |
| | 34 |
| | 5 |
| | 4 |
|
| Expected return on plan assets | (203 | ) | | (46 | ) | | (64 | ) | | (9 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
| Net (gain)/loss | 45 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost | $ | 23 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Nine Months Ended September 30, 2016 | | | | | | | | | |
| Service cost | $ | 192 |
| | $ | 43 |
| | $ | 52 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | 311 |
| | 71 |
| | 102 |
| | 14 |
| | 14 |
|
| Expected return on plan assets | (577 | ) | | (138 | ) | | (193 | ) | | (26 | ) | | (26 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 10 |
| | 2 |
| | 4 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | 120 |
| | 30 |
| | 41 |
| | 5 |
| | 5 |
|
| Net periodic pension cost | $ | 56 |
| | $ | 8 |
| | $ | 6 |
| | $ | 3 |
| | $ | 3 |
|
| Three Months Ended September 30, 2015 | | | | | | | | | |
| Service cost | $ | 65 |
| | $ | 14 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 111 |
| | 26 |
| | 38 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (181 | ) | | (44 | ) | | (62 | ) | | (8 | ) | | (8 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 6 |
| | 2 |
| | 2 |
| | 1 |
| | — |
|
| Net (gain)/loss | 53 |
| | 14 |
| | 19 |
| | 2 |
| | 3 |
|
| Net periodic pension cost | $ | 54 |
| | $ | 12 |
| | $ | 15 |
| | $ | 3 |
| | $ | 3 |
|
| Nine Months Ended September 30, 2015 | | | | | | | | | |
| Service cost | $ | 193 |
| | $ | 44 |
| | $ | 54 |
| | $ | 9 |
| | $ | 9 |
|
| Interest cost | 333 |
| | 79 |
| | 115 |
| | 15 |
| | 16 |
|
| Expected return on plan assets | (543 | ) | | (133 | ) | | (188 | ) | | (24 | ) | | (25 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 19 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
|
| Net (gain)/loss | 161 |
| | 41 |
| | 57 |
| | 7 |
| | 8 |
|
| Net periodic pension cost | $ | 163 |
| | $ | 36 |
| | $ | 45 |
| | $ | 8 |
| | $ | 9 |
|
Table of Contents |
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended March 31, 2017 | | | | | | | | | |
| Service cost | $ | 73 |
| | $ | 16 |
| | $ | 19 |
| | $ | 3 |
| | $ | 4 |
|
| Interest cost | 114 |
| | 24 |
| | 34 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (224 | ) | | (49 | ) | | (71 | ) | | (10 | ) | | (10 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 3 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 40 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost (income) | $ | 6 |
| | $ | 2 |
| | $ | (3 | ) | | $ | — |
| | $ | 1 |
|
| Three Months Ended March 31, 2016 | | | | | | | | | |
| Service cost | $ | 62 |
| | $ | 14 |
| | $ | 17 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | 100 |
| | 24 |
| | 34 |
| | 5 |
| | 5 |
|
| Expected return on plan assets | (187 | ) | | (46 | ) | | (64 | ) | | (9 | ) | | (9 | ) |
| Amortization: | | | | | | | | | |
| Prior service costs | 4 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | 38 |
| | 10 |
| | 14 |
| | 2 |
| | 2 |
|
| Net periodic pension cost | $ | 17 |
| | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Postretirement Benefits | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | |
| Pension Plans | | Southern Company Gas |
| | (in millions) | (in millions) |
| Three Months Ended September 30, 2016 | | | | | | | | | | |
| Successor – Three Months Ended March 31, 2017 | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| $ | 6 |
|
| Interest cost | 20 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| 10 |
|
| Expected return on plan assets | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| (18 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
| — |
|
| Net (gain)/loss | 5 |
| | — |
| | 3 |
| | — |
| | 1 |
| 5 |
|
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
| |
| Nine Months Ended September 30, 2016 | | | | | | | | | | |
| Net periodic pension cost | | $ | 3 |
|
| | | |
| | | |
| Predecessor – Three Months Ended March 31, 2016 | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| $ | 6 |
|
| Interest cost | 55 |
| | 14 |
| | 22 |
| | 2 |
| | 2 |
| 10 |
|
| Expected return on plan assets | (44 | ) | | (19 | ) | | (17 | ) | | (1 | ) | | (1 | ) | (16 | ) |
| Amortization: | | | | | | | | | | |
| Prior service costs | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
| — |
|
| Net (gain)/loss | 12 |
| | 1 |
| | 7 |
| | — |
| | 1 |
| 6 |
|
| Net periodic postretirement benefit cost | $ | 44 |
| | $ | 3 |
| | $ | 18 |
| | $ | 2 |
| | $ | 3 |
| |
| Three Months Ended September 30, 2015 | | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| |
| Interest cost | 20 |
| | 5 |
| | 9 |
| | — |
| | 1 |
| |
| Expected return on plan assets | (15 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
| |
| Amortization: | | | | | | | | | | |
| Prior service costs | 1 |
| | 2 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | 4 |
| | — |
| | 2 |
| | — |
| | — |
| |
| Net periodic postretirement benefit cost | $ | 16 |
| | $ | 2 |
| | $ | 7 |
| | $ | 1 |
| | $ | 1 |
| |
| Nine Months Ended September 30, 2015 | | | | | | | | | | |
| Service cost | $ | 17 |
| | $ | 4 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
| |
| Interest cost | 59 |
| | 15 |
| | 26 |
| | 2 |
| | 3 |
| |
| Expected return on plan assets | (44 | ) | | (19 | ) | | (18 | ) | | (1 | ) | | (1 | ) | |
| Amortization: | | | | | | | | | | |
| Prior service costs | 3 |
| | 3 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | 13 |
| | 1 |
| | 8 |
| | — |
| | — |
| |
| Net periodic postretirement benefit cost | $ | 48 |
| | $ | 4 |
| | $ | 21 |
| | $ | 2 |
| | $ | 3 |
| |
| Net periodic pension cost | | $ | 6 |
|
|
| | | | | | | | | | | | | | | | | | | |
| Postretirement Benefits | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | (in millions) |
| Three Months Ended March 31, 2017 | | | | | | | | | |
| Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 20 |
| | 5 |
| | 7 |
| | 1 |
| | 1 |
|
| Expected return on plan assets | (16 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 2 |
| | — |
| | 2 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 5 |
| | $ | 1 |
| | $ | 1 |
|
| Three Months Ended March 31, 2016 | | | | | | | | | |
| Service cost | $ | 5 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| Interest cost | 18 |
| | 5 |
| | 8 |
| | 1 |
| | 1 |
|
| Expected return on plan assets | (14 | ) | | (6 | ) | | (6 | ) | | — |
| | — |
|
| Amortization: | | | | | | | | | |
| Prior service costs | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | 3 |
| | — |
| | 2 |
| | — |
| | — |
|
| Net periodic postretirement benefit cost | $ | 14 |
| | $ | 1 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Table of Contents |
| | | |
| Postretirement Benefits | Southern Company Gas |
| | (in millions) |
| Successor – Three Months Ended March 31, 2017 | |
| Service cost | $ | 1 |
|
| Interest cost | 3 |
|
| Expected return on plan assets | (2 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
| | |
| | |
| Predecessor – Three Months Ended March 31, 2016 | |
| Service cost | $ | 1 |
|
| Interest cost | 3 |
|
| Expected return on plan assets | (2 | ) |
| Amortization: | |
| Prior service costs | (1 | ) |
| Net (gain)/loss | 1 |
|
| Net periodic postretirement benefit cost | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Net Operating Loss
Southern Company expects to be in a consolidated net operating loss (NOL) position for income tax purposes for the 2016 tax year. The NOL will limit the amount of positive cash flows resulting from bonus depreciation, ITCs, and PTCs for the tax year and will significantly increase deferred tax assets for the NOL and tax credit carryforwards. Portions of the NOL are expected to be carried back to prior tax years and forward to the 2017 tax year, which could further increase existing tax credit carryforwards. The ultimate outcome of this matter cannot be determined at this time.
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.2$1.9 billion and $26 million, respectively, as of September 30, 2016 and $554 million and $1 million, respectively,March 31, 2017 compared to $1.8 billion as of December 31, 2015. Additionally, Southern Company had $165 million of state ITC carryforwards for the state of Georgia as of September 30, 2016 compared to $188 million as of December 31, 2015. See "Unrecognized Tax Benefits" herein for further information.2016.
The federal ITC carryforwards as of September 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of September 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2021. The state ITC carryforwards for the state of Georgia as of September 30, 2016 expire between 2020 and 20262032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The acquisition of additional renewable projects and carrying back the endfederal net operating loss, as well as potential tax reform legislation on existing renewable incentives, could further delay existing tax credit carryforwards. The ultimate outcome of 2022.these matters cannot be determined at this time.
Effective Tax Rate
Southern Company
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.
Southern Company's effective tax rate was 29.1%32.1% for the ninethree months ended September 30, 2016March 31, 2017 compared to 33.5%30.2% for the corresponding period in 2015.2016. The effective tax rate decreaseincrease was primarily due to increased federal incomehigher pre-tax earnings resulting from the Merger with Southern Company Gas and decreased tax benefits from ITCs, and PTCs at Southern Power, partially offset by an increase in tax benefits from wind PTCs and state apportionment rate changes.
Southern Company recognizes PTCs when wind energy is generated and sold (using the impact of additionalprescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax benefits recognized in 2015.rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Mississippi Power
Mississippi Power's effective tax (benefit) rate was (276.2)(58.7)% for the ninethree months ended September 30, 2016March 31, 2017 compared to (20.9)(850.4)% for the corresponding period in 2015.2016. The effective tax rate decreaseincrease was primarily due to an increase in tax benefits related to the estimated probable losses on construction of the Kemper IGCC and an increase in non-taxable AFUDC equity.IGCC.
Southern Power
Southern Power's effective tax (benefit) rate was (88.9)(385.9)% for the ninethree months ended September 30, 2016March 31, 2017 compared to 6.9%(84.0)% for the corresponding period in 2015.2016. The effective tax rate decrease was primarily due to increased federal incomeadditional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by a decrease in tax benefits from ITCs related to solar projects expected toITCs.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be placed in service in 2016 and additional PTCs related tosignificantly impacted by wind projects in 2016 compared to 2015.generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes during 2016the three months ended March 31, 2017 for unrecognized tax benefits were as follows:
| | | | Mississippi Power | | Southern Power | | Southern Company | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) | (in millions) |
| Unrecognized tax benefits as of December 31, 2015 | $ | 421 |
| | $ | 8 |
| | $ | 433 |
| |
| Unrecognized tax benefits as of December 31, 2016 | | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | — |
| | 12 |
| | 12 |
| 3 |
| | 1 |
| | 9 |
|
| Tax positions from prior periods | 18 |
| | (1 | ) | | 13 |
| — |
| | — |
| | 7 |
|
| Balance as of September 30, 2016 | $ | 439 |
| | $ | 19 |
| | $ | 458 |
| |
| Balance as of March 31, 2017 | | $ | 468 |
| | $ | 18 |
| | $ | 500 |
|
The tax positions from current periods primarily relate to federal income tax benefits from deferred ITCs and ITCs impacting the estimated annual effective tax rate for interim reporting purposes. The tax positions from prior periods primarily relate to federal incomestate tax benefits from ITCs, and from deductions for Kemper IGCC-relatedcharitable contribution carryforwards that will be impacted as a result of the proposed settlement of research and experimental (R&E) expenditures.expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" belowherein 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 effective tax rate, if recognized, is as follows:
| | | | As of September 30, 2016 | | As of December 31, 2015 | As of March 31, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) | (in millions) |
| Tax positions impacting the effective tax rate | $ | 1 |
| | $ | 19 |
| | $ | 20 |
| | $ | 10 |
| $ | 4 |
| | $ | 18 |
| | $ | 36 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | 438 |
| | — |
| | 438 |
| | 423 |
| 464 |
| | — |
| | 464 |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 439 |
| | $ | 19 |
| | $ | 458 |
| | $ | 433 |
| $ | 468 |
| | $ | 18 |
| | $ | 500 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to federal deferred income tax benefits from ITCscredits and Southern Company's estimate of the uncertainty related to the amount of those benefits. The impact onbenefits, and state tax benefits and charitable contribution carryforwards that will be impacted as a result of the effective tax rate is determined based onproposed settlement of R&E expenditures associated with the amount of ITCs, which is uncertain.Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are not able to be recognized due to a federal audit adjustment equal toin the amount that has been estimated, amount, the amount of tax credit carryforwards discussed above would be reduced by approximately $94$98 million.
Accrued interest for all tax positions other than the Section 174 R&E deductions disclosed below was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued 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 and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for more information.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition, the pre-Merger Southern Company Gas 2014 federal tax
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
return is currently under audit. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Section 174 Research and Experimental Deduction
Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. Subsequent to September 30,In December 2016, Southern Company and Mississippi Power responded to a notice of proposed assessment from the IRS which is continuingreached a proposed settlement, subject to reviewapproval of the underlying supportU.S. Congress Joint Committee on Taxation, resolving a methodology for the deduction.these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions oftotaling approximately $438$464 million and associated interest of $24$32 million as of September 30, 2016. ItMarch 31, 2017. This matter is reasonably possible that this matter willexpected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are 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 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 net basis. See Note (C) 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.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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 the natural gas distribution utilities of Southern Company Gas 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 of Southern Company Gas 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 Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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 traditional electric operating companies (with respect to wholesale generating capacity), and Southern Power and Southern Company Gas 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 Southern Power, and Southern Company GasPower may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity and natural gas.
electricity. Southern Company Gas uses storage and transportation capacity contracts to manage market price risks. Southern Company Gas 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 Southern Company Gas will receive in the future, resulting in a positive net operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futures and over-the-counter (OTC) contracts to sell natural gas at that future price to substantially protect the operating margin ultimately realized when the stored natural gas is sold. Southern Company Gas also enters into transactions to secure transportation capacity between delivery points in order to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
serve its customers and various markets. Southern Company Gas uses NYMEX futuresretains exposure to price changes that can, in a volatile energy market, be material and OTC contracts to capture the price differential between the locations served by the capacity in order to substantially protect the operating margin ultimately realized when natural gas is physically flowed between the delivery points. These contracts generally meet the definitioncan adversely affect its results of derivatives, but are not designated as hedges for accounting purposes.operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of 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 Southern Company Gas'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 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 September 30, 2016,March 31, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date 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 for derivatives not designated as hedges, were as follows:
| | | | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | (in millions) | |
Southern Company(*) | 540 | | 2020 | | 2022 | 503 | | 2021 | | 2024 |
| Alabama Power | 75 | | 2020 | | — | 71 | | 2020 | | — |
| Georgia Power | 148 | | 2020 | | — | 155 | | 2020 | | — |
| Gulf Power | 57 | | 2020 | | — | 42 | | 2020 | | — |
| Mississippi Power | 37 | | 2020 | | — | 37 | | 2021 | | — |
| Southern Power | 9 | | 2017 | | 2016 | 21 | | 2017 | | 2017 |
Southern Company Gas(*) | | 177 | | 2019 | | 2024 |
| |
| (*) | Southern Company's and Southern Company Gas' derivative instruments are comprised ofinclude 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. Southern Company Gas' volume represents the net of long natural gas positions of 3.23.4 billion mmBtu and short natural gas positions of 2.93.2 billion mmBtu as of September 30, 2016.March 31, 2017, which is also included in Southern Company's total volume. |
In addition to the volumes discussed in the above, table, 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 510 million mmBtu for Southern Company, 4 million mmbtu for Georgia Power, 3 million mmBtu for Southern Power, and Georgia1 million mmBtu for each of Alabama Power, Gulf Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2017March 31, 2018 are $10 million for Southern Power and immaterial for all other registrants.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 2016,March 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) at September 30, 2016 | Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value
Gain (Loss) at March 31, 2017 |
| | (in millions) | | | | (in millions) | (in millions) | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | Cash Flow Hedges of Forecasted Debt | | | Cash Flow Hedges of Forecasted Debt | | |
| Gulf Power | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | (6 | ) | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | — |
|
| Cash Flow Hedges of Existing Debt | Cash Flow Hedges of Existing Debt | | | Cash Flow Hedges of Existing Debt | | |
| Mississippi Power | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | (1 | ) | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | 4 |
|
| Fair Value Hedges of Existing Debt | Fair Value Hedges of Existing Debt | | | Fair Value Hedges of Existing Debt | | |
Southern Company(a) | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | 1 |
| |
Southern Company(a) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 9 |
| |
Southern Company(*) | | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | — |
|
Southern Company(*) | | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 1 |
|
Southern Company(*) | | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (21 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | 2 |
| 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
|
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 5 |
| 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (3 | ) |
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | 2 |
| 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 1 |
|
| Derivatives not Designated as Hedges | | | |
| Southern Power | 65 |
| (b)(e) | 3-month
LIBOR | 2.50% | October 2016 | (f) | — |
| |
| Southern Power | 47 |
| (c)(e) | 3-month
LIBOR | 2.21% | October 2016 | (f) | — |
| |
| Southern Power | 65 |
| (d)(e) | 3-month
LIBOR | 2.21% | November 2016 | (g) | — |
| |
| Southern Company Consolidated | $ | 2,657 |
| | $ | 12 |
| $ | 3,980 |
| | $ | (18 | ) |
| |
(a)(*) | Represents the Southern Company parent entity. |
| |
(b) | Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
(c) | Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. Subsequent to September 30, 2016, Roserock extended the maturity date of its swaption to December 31, 2016. |
| |
(d) | Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. |
| |
(e) | Amortizing notional amount. |
| |
(f) | Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap. |
| |
(g) | Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap. |
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 September 30, 2017March 31, 2018 are $(21) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company and certain subsidiaries have deferred gains and losses 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.
At September 30, 2016,March 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 September 30, 2016 | Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value
Gain (Loss) at March 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) | (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | Cash Flow Hedges of Existing Debt | | | | | Cash Flow Hedges of Existing Debt | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (2 | ) | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (35 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | 1 |
| 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (27 | ) |
| Total | $ | 1,241 |
| | € | 1,100 |
| | $ | (1 | ) | $ | 1,241 |
| | € | 1,100 |
| | $ | (62 | ) |
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 September 30, 2017March 31, 2018 are $(12)$24 million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Derivative contracts of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are presented on a net basis in the financial statements to the extent that the contracts are subject to netting arrangements. Some of these energy-related and interest rateenter 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. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
At September 30, 2016, the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Southern Company | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 20 |
| $ | (62 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| (53 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 33 |
| $ | (115 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 4 |
| $ | (6 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (1 | ) |
Table of Contents |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 48 |
| $ | 30 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 6 |
| 38 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 54 |
| $ | 68 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 14 |
| $ | 5 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | 13 |
| — |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 32 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 27 |
| $ | 99 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 306 |
| $ | 271 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 438 |
| $ | 385 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 519 |
| $ | 552 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (303 | ) | $ | (395 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 216 |
| $ | 157 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Interest rate derivatives: |
|
|
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 8 |
| $ | (7 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 11 |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 46 |
| $ | (38 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 305 |
| $ | (345 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 58 |
| (74 | ) |
| Total derivatives not designated as hedging instruments | $ | 363 |
| $ | (419 | ) |
| Gross amounts of recognized assets and liabilities | $ | 442 |
| $ | (572 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (283 | ) | $ | 394 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 159 |
| $ | (178 | ) |
| | | |
| Alabama Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 4 |
| $ | (14 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| (7 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 8 |
| $ | (21 | ) |
| Gross amounts of recognized assets and liabilities | $ | 8 |
| $ | (21 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (7 | ) | $ | 7 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 1 |
| $ | (14 | ) |
| | | |
| Georgia Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 7 |
| $ | (5 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 8 |
| (11 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 15 |
| $ | (16 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | 5 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 10 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 25 |
| $ | (16 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (11 | ) | $ | 11 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 14 |
| $ | (5 | ) |
| | | |
Table of Contents |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Alabama Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 9 |
| $ | 5 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 5 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 4 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 20 |
| $ | 2 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| 11 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 24 |
| $ | 13 |
| $ | 44 |
| $ | 8 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 4 |
| — |
| 3 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 4 |
| $ | 2 |
| $ | 3 |
|
| Gross amounts recognized | $ | 26 |
| $ | 17 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 20 |
| $ | 11 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 2 |
| $ | 14 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 17 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 29 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| | As of September 30, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities |
| | (in millions) |
| Gulf Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | 1 |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| (27 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (51 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Liabilities from risk management activities | $ | — |
| $ | (6 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (57 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (56 | ) |
| | | |
| Mississippi Power | | |
| Derivatives designated as hedging instruments for regulatory purposes | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (13 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| (8 | ) |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 |
| $ | (21 | ) |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Interest rate derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (1 | ) |
| Gross amounts of recognized assets and liabilities | $ | 1 |
| $ | (22 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | — |
| $ | (21 | ) |
| | | |
| Southern Power | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | (3 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
|
| Foreign currency derivatives: | | |
| Other current assets/Other current liabilities | $ | — |
| $ | (24 | ) |
| Other deferred charges and assets/Other deferred credits and liabilities | 23 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 25 |
| $ | (27 | ) |
| Derivatives not designated as hedging instruments | | |
| Energy-related derivatives: | | |
| Other current assets/Other current liabilities | $ | 1 |
| $ | — |
|
| Gross amounts of recognized assets and liabilities | $ | 26 |
| $ | (27 | ) |
Gross amounts offset in the Balance Sheet(*) | $ | (1 | ) | $ | 1 |
|
| Net amounts of assets and liabilities presented in the Balance Sheet | $ | 25 |
| $ | (26 | ) |
| |
(*) | Includes any cash/financial collateral pledged or received. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: |
| | | | | | | | | | | | | | | |
| Asset Derivatives at December 31, 2015 |
| | Fair Value |
| Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Southern Power |
| | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 3 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 3 |
| $ | — |
| $ | — |
| $ | — |
| $ | 3 |
|
| Interest rate derivatives: | | | | | |
| Other current assets | 19 |
| — |
| 5 |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | | |
| Energy-related derivatives: | | | | | |
| Other current assets | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | 1 |
|
| Interest rate derivatives: | | | | | |
| Other current assets | 3 |
| — |
| — |
| — |
| 3 |
|
| Total derivatives not designated as hedging instruments | $ | 4 |
| $ | — |
| $ | — |
| $ | — |
| $ | 4 |
|
| Total asset derivatives | $ | 29 |
| $ | 1 |
| $ | 7 |
| $ | 1 |
| $ | 7 |
|
Table of Contents |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | 7 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 5 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 12 |
| $ | 4 |
| $ | 11 |
|
| 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 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 4 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 7 |
| $ | 12 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 10 |
| $ | 4 |
| $ | 8 |
|
| | | | | |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 13 |
| $ | 4 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 13 |
| $ | 66 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | 1 |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 2 |
| $ | 1 |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 15 |
| $ | 67 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 12 |
| $ | 64 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Liability Derivatives at December 31, 2015 |
| | Fair Value |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Power |
| | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 130 |
| $ | 40 |
| $ | 12 |
| $ | 49 |
| $ | 29 |
| |
| Other deferred credits and liabilities | 87 |
| 15 |
| 3 |
| 51 |
| 18 |
| |
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 217 |
| $ | 55 |
| $ | 15 |
| $ | 100 |
| $ | 47 |
| N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 2 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2 |
|
| Interest rate derivatives: | | | | | | |
| Liabilities from risk management activities | 23 |
| 15 |
| — |
| — |
| — |
| — |
|
| Other deferred credits and liabilities | 7 |
| — |
| 6 |
| — |
| — |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 32 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | 2 |
|
| Derivatives not designated as hedging instruments | | | | | | |
| Energy-related derivatives: | | | | | | |
Liabilities from risk management activities(*) | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 1 |
|
| Total liability derivatives | $ | 250 |
| $ | 70 |
| $ | 21 |
| $ | 100 |
| $ | 47 |
| $ | 3 |
|
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Southern Company Gas | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 14 |
| $ | 2 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 14 |
| $ | 2 |
| $ | 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 | $ | 1 |
| $ | 1 |
| $ | 4 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 304 |
| $ | 270 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 436 |
| $ | 384 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 451 |
| $ | 387 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (272 | ) | $ | (364 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 179 |
| $ | 23 |
| $ | 146 |
| $ | 72 |
|
| |
| (*) | Georgia Power, Mississippi Power,Gross amounts offset include cash collateral held on deposit in broker margin accounts of $92 million and Southern Power include current liabilities related to derivatives in other current liabilities.$62 million as of March 31, 2017 and December 31, 2016, respectively. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In 2015, the derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are reported gross on each registrant's 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. Amounts related to energy-related derivative contracts and interest rate derivative contracts at DecemberAt March 31, 2015 are presented in the following table:
|
| | | | | | | | | | | | | | | | | | |
| Derivative Contracts at December 31, 2015 |
| | Fair Value |
| | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Power |
| | (in millions) |
| Assets | | | | | | |
| Energy-related derivatives: | | | | | | |
Energy-related derivatives presented in the Balance Sheet(a) | $ | 7 |
| $ | 1 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | 4 |
|
Gross amounts not offset in the Balance Sheet(b) | (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative assets | $ | 1 |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 3 |
|
| Interest rate derivatives: | | | | | | |
Interest rate derivatives presented in the Balance Sheet(a) | $ | 22 |
| $ | — |
| $ | 5 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet(b) | (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative assets | $ | 13 |
| $ | — |
| $ | 1 |
| $ | 1 |
| $ | — |
| $ | 3 |
|
| Liabilities | | | | | | |
| Energy-related derivatives: | | | | | | |
Energy-related derivatives presented in the Balance Sheet(a) | $ | 220 |
| $ | 55 |
| $ | 15 |
| $ | 100 |
| $ | 47 |
| $ | 3 |
|
Gross amounts not offset in the Balance Sheet(b) | (6 | ) | (1 | ) | (2 | ) | — |
| — |
| (1 | ) |
| Net energy-related derivative liabilities | $ | 214 |
| $ | 54 |
| $ | 13 |
| $ | 100 |
| $ | 47 |
| $ | 2 |
|
| Interest rate derivatives: | | | | | | |
Interest rate derivatives presented in the Balance Sheet(a) | $ | 30 |
| $ | 15 |
| $ | 6 |
| $ | — |
| $ | — |
| $ | — |
|
Gross amounts not offset in the Balance Sheet(b) | (9 | ) | — |
| (4 | ) | — |
| — |
| — |
|
| Net interest rate derivative liabilities | $ | 21 |
| $ | 15 |
| $ | 2 |
| $ | — |
| $ | — |
| $ | — |
|
| |
(a) | As of December 31, 2015, none of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty in the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented in the balance sheets are the same. |
| |
(b) | Includes gross amounts subject to netting terms that are not offset in the balance sheets and any cash/financial collateral pledged or received. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At September 30, 20162017 and December 31, 2015,2016, 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:
| | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2016 | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2017 | | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2017 |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(b) |
| | (in millions) | (in millions) | |
| Energy-related derivatives: | | |
| Other regulatory assets, current | $ | (52 | ) | $ | (10 | ) | $ | (2 | ) | $ | (24 | ) | $ | (13 | ) | $ | (19 | ) | $ | (1 | ) | $ | — |
| $ | (12 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (42 | ) | (4 | ) | (4 | ) | (26 | ) | (8 | ) | (32 | ) | (3 | ) | (7 | ) | (17 | ) | (5 | ) | — |
|
Other regulatory liabilities, current(a) | 8 |
| 1 |
| 4 |
| — |
| — |
| 33 |
| 5 |
| 18 |
| — |
| 1 |
| 9 |
|
Other regulatory liabilities, deferred(b) | 1 |
| — |
| 1 |
| — |
| — |
| |
| Total energy-related derivative gains (losses) | $ | (85 | ) | $ | (13 | ) | $ | (1 | ) | $ | (50 | ) | $ | (21 | ) | $ | (18 | ) | $ | 1 |
| $ | 11 |
| $ | (29 | ) | $ | (9 | ) | $ | 8 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $4 million at March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
|
| | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2015 |
Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Gulf Power | Mississippi Power |
| | (in millions) |
| Energy-related derivatives: | | | | | |
| Other regulatory assets, current | $ | (130 | ) | $ | (40 | ) | $ | (12 | ) | $ | (49 | ) | $ | (29 | ) |
| Other regulatory assets, deferred | (87 | ) | (15 | ) | (3 | ) | (51 | ) | (18 | ) |
Other regulatory liabilities, current(*) | 3 |
| 1 |
| 2 |
| — |
| — |
|
| Total energy-related derivative gains (losses) | $ | (214 | ) | $ | (54 | ) | $ | (13 | ) | $ | (100 | ) | $ | (47 | ) |
| |
(*)(c) | Georgia Power includes otherFair value gains and losses recorded in regulatory assets and liabilities currentinclude cash collateral held on deposit in other current liabilities.broker margin accounts of $8 million at December 31, 2016. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three months ended September 30,March 31, 2017 and 2016, and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments 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) |
| | Statements of Income Location | Amount | | Statements of Income Location | Amount |
| | 2016 | | 2015 | | 2016 | | 2015 | 2017 | | 2016 | | 2017 | | 2016 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Southern Company | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (11 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Interest rate derivatives | (6 | ) | | (28 | ) | | Interest expense, net of amounts capitalized | (6 | ) | | (2 | ) | 1 |
| | (190 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (3 | ) |
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
| (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 7 |
| | — |
| | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | 31 |
| | $ | (28 | ) | | $ | (4 | ) | | $ | (2 | ) | $ | (14 | ) | | $ | (190 | ) | | $ | 2 |
| | $ | (4 | ) |
| Alabama Power | | | | | | | | |
| Gulf Power | | | | | | | | |
| Energy-related derivatives | | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | $ | — |
| | $ | (10 | ) | | Interest expense, net of amounts capitalized | $ | (2 | ) | | $ | (1 | ) | — |
| | (5 | ) | | Interest expense, net of amounts capitalized | — |
| | — |
|
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (18 | ) | | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | |
| Total | | $ | (1 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (8 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Foreign currency derivatives | 37 |
| | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
| (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 7 |
| | — |
| | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | 37 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| $ | (12 | ) | | $ | — |
| | $ | 7 |
| | $ | (1 | ) |
| |
| (*) | 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 the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the nine months ended September 30, 2016 and 2015,Southern Company Gas, the pre-tax effectseffect of energy-related derivatives, interest rateenergy related derivatives and foreign currencyinterest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the three months ended March 31, 2017 and the predecessor period of January 1, 2016 through March 31, 2016 were as follows:
| | | | 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 | Gain (Loss)
Recognized in OCI
on Derivative
(Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into
Income (Effective Portion) | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 | | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | Statements of Income Location | Amount | |
| | 2016 | | 2015 | | 2016 | | 2015 | (in millions) | | | (in millions) | | (in millions) | | | (in millions) |
| | (in millions) | | | (in millions) | |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| $ | (2 | ) | | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | — |
|
| Interest rate derivatives | (189 | ) | | (26 | ) | | Interest expense, net of amounts capitalized | (13 | ) | | (7 | ) | — |
| | | (45 | ) | | Interest expense, net of amounts capitalized | — |
| | | 1 |
|
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
| |
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
| |
| Total | $ | (191 | ) | | $ | (26 | ) | | $ | (32 | ) | | $ | (7 | ) | $ | (2 | ) | | | $ | (45 | ) | | $ | — |
| | | $ | 1 |
|
| Alabama Power | | | | | | | | |
| Interest rate derivatives | $ | (3 | ) | | $ | (9 | ) | | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | (2 | ) | |
| Georgia Power | | | | | | | | |
| Interest rate derivatives | $ | — |
| | $ | (17 | ) | | Interest expense, net of amounts capitalized | $ | (3 | ) | | $ | (3 | ) | |
| Gulf Power | | | | | | | | |
| Interest rate derivatives | $ | (7 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | — |
| | $ | — |
| |
| Mississippi Power | | | | | | | | |
| Interest rate derivatives | $ | (1 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | (1 | ) | |
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Amortization | $ | 1 |
| | $ | — |
| |
| Interest rate derivatives | — |
| | — |
| | Interest expense, net of amounts capitalized | (1 | ) | | (1 | ) | |
| Foreign currency derivatives | (1 | ) | | — |
| | Interest expense, net of amounts capitalized | (7 | ) | | — |
| |
| | | | | | Other income (expense), net(*) | (13 | ) | | — |
| |
| Total | $ | (2 | ) | | $ | — |
| | $ | (20 | ) | | $ | (1 | ) | |
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:
|
| | | | | | | | |
| | | Gain (Loss) |
| | | Three Months Ended
March 31, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | $ | — |
|
| | Cost of natural gas | (3 | ) | | — |
|
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | $ | — |
|
| |
| (*) | The reclassification from accumulated OCI into other income (expense), net completely offsets currencyExcludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the three months ended March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| | | Gain (Loss) |
| | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | | (in millions) | | | (in millions) |
| Southern Company Gas | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | | $ | 20 |
|
| | Cost of natural gas | (3 | ) | | | (1 | ) |
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | | $ | 19 |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the successor three months ended March 31, 2017 and losses arising from changes in$3 million for the U.S. currency exchange rates used to record the euro-denominated notes.predecessor three months ended March 31, 2016. |
For the three and nine months ended September 30,March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and 2015,interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three months ended March 31, 2017 and 2016, 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) |
| | | Three Months Ended September 30, | Nine Months Ended September 30, |
| Derivative Category | Statements of Income Location | 2016 | | 2015 | 2016 | | 2015 |
| | | (in millions) | (in millions) |
| Southern Company | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (9 | ) | | $ | 15 |
| $ | 15 |
| | $ | 19 |
|
| Georgia Power | | | | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (5 | ) | | $ | 7 |
| $ | 10 |
| | $ | 9 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | |
| Derivatives in Fair Value Hedging Relationships |
| | | Gain (Loss) |
| | | Three Months Ended March 31, |
| Derivative Category | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (8 | ) | | $ | 20 |
|
| Georgia Power | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | 14 |
|
For the three and nine months ended September 30,March 31, 2017 and 2016, and 2015, 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.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
For the three and nine months ended September 30, 2016 and 2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.
Contingent FeaturesSouthern Power
Southern Company,Power's effective tax (benefit) rate was (385.9)% for the traditional electric operating companies, three months ended March 31, 2017 compared to (84.0)% for the corresponding period in 2016. The effective tax rate decrease was primarily due to additional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by a decrease in tax benefits from ITCs.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company Gas do not have any credit arrangementsPower uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes during the three months ended March 31, 2017 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2016 | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | 3 |
| | 1 |
| | 9 |
|
| Tax positions from prior periods | — |
| | — |
| | 7 |
|
| Balance as of March 31, 2017 | $ | 468 |
| | $ | 18 |
| | $ | 500 |
|
The tax positions from current and prior periods primarily relate to state tax benefits and charitable contribution carryforwards that would require material changes in payment schedules or terminationswill be impacted as a result of the proposed settlement of research and experimental (R&E) expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a credit rating downgrade. Theregross basis without considering the related federal or state income tax impact.
The impact on the effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | | | | | |
| | As of March 31, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | 4 |
| | $ | 18 |
| | $ | 36 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | 464 |
| | — |
| | 464 |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 468 |
| | $ | 18 |
| | $ | 500 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to federal deferred income tax credits and Southern Company's estimate of the uncertainty related to the amount of those benefits, and state tax benefits and charitable contribution carryforwards that will be impacted as a result of the proposed settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are certain derivatives that could require collateral, but not accelerated payment,able to be recognized due to a federal audit adjustment in the eventamount that has been estimated, the amount of varioustax credit rating changescarryforwards discussed above would be reduced by approximately $98 million.
Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all periods presented.
All of certainthe registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued 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 and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for more information.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company subsidiaries. At September 30,has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition, the pre-Merger Southern Company Gas 2014 federal tax
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
return is 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 reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had $111unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of collateral posted with derivative counterparties. The amount$32 million as of collateral posted with the derivative counterparties for all other registrants was immaterial.
At September 30, 2016, the fair value of derivative liabilities with contingent features was $22 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $22 million for all registrants and include certain agreements that could require collateralMarch 31, 2017. This matter is expected to be resolved in the event that one or more Southern Company power pool participants or Southern Company has a credit rating change to below investment grade.next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
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.Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses relatedmarket risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to financialthese exposures, each company nets its 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 eventbalance sheets as either assets or liabilities and are presented on a net basis. See Note (C) for additional information. In the statements of counterparties' nonperformance. 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.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas only enter into agreementsenergy-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 the 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 of Southern Company Gas 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 Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of 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 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 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 March 31, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with counterpartiesthe longest hedge date 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 for derivatives not designated as hedges, were as follows:
|
| | | | | |
| | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | | | |
Southern Company(*) | 503 | | 2021 | | 2024 |
| Alabama Power | 71 | | 2020 | | — |
| Georgia Power | 155 | | 2020 | | — |
| Gulf Power | 42 | | 2020 | | — |
| Mississippi Power | 37 | | 2021 | | — |
| Southern Power | 21 | | 2017 | | 2017 |
Southern Company Gas(*) | 177 | | 2019 | | 2024 |
| |
| (*) | Southern Company's and Southern Company Gas' derivative instruments include 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. Southern Company Gas' volume represents the net of long natural gas positions of 3.4 billion mmBtu and short natural gas positions of 3.2 billion mmBtu as of March 31, 2017, which is also included in Southern Company's total volume. |
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 10 million mmBtu for Southern Company, 4 million mmbtu for Georgia Power, 3 million mmBtu for Southern Power, and 1 million mmBtu for each of Alabama Power, Gulf Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2018 are $10 million for Southern Power and immaterial for all other registrants.
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 March 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) at March 31, 2017 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | | | | | | |
| Gulf Power | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | — |
|
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | 4 |
|
| Fair Value Hedges of Existing Debt | | | | | | |
Southern Company(*) | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | — |
|
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 1 |
|
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (21 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
|
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (3 | ) |
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 1 |
|
| Southern Company Consolidated | $ | 3,980 |
| | | | | | $ | (18 | ) |
| |
| (*) | Represents the Southern Company parent entity. |
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 March 31, 2018 are immaterial for all registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company and certain subsidiaries have investment grade credit ratings by Moody'sdeferred gains and S&Plosses 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 with counterparties who have posted collaterallosses 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 cover potential credit exposure. earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
At March 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 March 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (35 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (27 | ) |
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (62 | ) |
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 March 31, 2018 are $24 million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policiesenter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and controlspayables for routine billing and offsets related to determineevents of default and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, andsettlements. Southern Company Gas'and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. Southern Company GasThese agreements may require counterparties to pledge additional collateral when deemed necessary. Therefore, Southern Company, the traditional electric operating companies,contain provisions that permit netting across product lines and Southern Power do not anticipate a material adverse effectagainst cash collateral. The fair value amounts of derivative assets and liabilities on the financial statements as a result of counterparty nonperformance.
Southern Company
Mergerbalance sheet are presented net to the extent that there are netting arrangements or similar agreements with Southern Company Gas
Southern Company Gas, formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the distribution of natural gas through 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as of the acquisition date. The following table presents the preliminary purchase price allocation:follows:
|
| | | |
| Southern Company Gas Purchase Price | September 30, 2016 |
| | (in millions) |
| Current assets | $ | 1,557 |
|
| Property, plant, and equipment | 10,108 |
|
| Goodwill | 5,937 |
|
| Intangible assets | 400 |
|
| Regulatory assets | 1,118 |
|
| Other assets | 229 |
|
| Current liabilities | (2,201 | ) |
| Other liabilities | (4,712 | ) |
| Long-term debt | (4,261 | ) |
| Noncontrolling interests | (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 $5.9 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 estimated fair values noted above are preliminary and are subject to change upon finalization of the purchase accounting assessment as additional information related to the fair value of assets and liabilities becomes available. Subsequent adjustments to the preliminary purchase price allocation are not expected to have a material impact on the results of operations and financial position of Southern Company.
The preliminary 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 the consolidated financial statements from the date of acquisition and consist of operating revenues of $543 million and net income of $4 million.
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.
|
| | | | | | |
| | For the Nine Months Ended September 30, |
| | 2016 | 2015 |
| | |
Operating revenues (in millions) | $ | 16,609 |
| $ | 16,865 |
|
Net income attributable to Southern Company (in millions) | $ | 2,369 |
| $ | 2,269 |
|
| Basic EPS | $ | 2.50 |
| $ | 2.43 |
|
| Diluted EPS | $ | 2.48 |
| $ | 2.42 |
|
Table of Contents |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 48 |
| $ | 30 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 6 |
| 38 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 54 |
| $ | 68 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 14 |
| $ | 5 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | 13 |
| — |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 32 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 27 |
| $ | 99 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 306 |
| $ | 271 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 438 |
| $ | 385 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 519 |
| $ | 552 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (303 | ) | $ | (395 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 216 |
| $ | 157 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.
See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.
Acquisition of PowerSecure International, Inc.
On May 9, 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 allocation of the purchase price is as follows:
|
| | | |
| PowerSecure Purchase Price | September 30, 2016 |
| | (in millions) |
| Current assets | $ | 172 |
|
| Property, plant, and equipment | 46 |
|
| Goodwill | 284 |
|
| Intangible assets | 101 |
|
| Other assets | 6 |
|
| Current liabilities | (145 | ) |
| Long-term debt, including current portion | (18 | ) |
| Deferred credits and other liabilities | (17 | ) |
| 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 the 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.
Alliance with Bloom Energy Corporation
On October 24, 2016, a subsidiary of Southern Company acquired from an affiliate of Bloom Energy Corporation (Bloom) all of the equity interests of 2016 ESA HoldCo, LLC and its subsidiary, 2016 ESA Project Company, LLC.
Table of Contents |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Alabama Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 9 |
| $ | 5 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 5 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 4 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 20 |
| $ | 2 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| 11 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 24 |
| $ | 13 |
| $ | 44 |
| $ | 8 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 4 |
| — |
| 3 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 4 |
| $ | 2 |
| $ | 3 |
|
| Gross amounts recognized | $ | 26 |
| $ | 17 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 20 |
| $ | 11 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 2 |
| $ | 14 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 17 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 29 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2016 ESA Project Company, LLC expects to acquire 50 MWs of Bloom fuel cell systems to serve commercial |
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | 7 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 5 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 12 |
| $ | 4 |
| $ | 11 |
|
| 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 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 4 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 7 |
| $ | 12 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 10 |
| $ | 4 |
| $ | 8 |
|
| | | | | |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 13 |
| $ | 4 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 13 |
| $ | 66 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | 1 |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 2 |
| $ | 1 |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 15 |
| $ | 67 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 12 |
| $ | 64 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Southern Company Gas | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 14 |
| $ | 2 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 14 |
| $ | 2 |
| $ | 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 | $ | 1 |
| $ | 1 |
| $ | 4 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 304 |
| $ | 270 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 436 |
| $ | 384 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 451 |
| $ | 387 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (272 | ) | $ | (364 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 179 |
| $ | 23 |
| $ | 146 |
| $ | 72 |
|
| |
| (*) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $92 million and $62 million as of March 31, 2017 and December 31, 2016, respectively. |
At March 31, 2017 and industrial customers under long-term PPAs. In connection with this transaction, PowerSecure and Bloom agreed to pursue a strategic alliance to develop technology for behind-the-meter energy solutions.
Investment in Southern Natural Gas
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company 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. On AugustDecember 31, 2016, Southern Company assigned its rightsthe pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and obligations underdeferred were as follows:
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2017 |
Derivative Category and Balance Sheet Location | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(b) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (19 | ) | $ | (1 | ) | $ | — |
| $ | (12 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (32 | ) | (3 | ) | (7 | ) | (17 | ) | (5 | ) | — |
|
Other regulatory liabilities, current(a) | 33 |
| 5 |
| 18 |
| — |
| 1 |
| 9 |
|
| Total energy-related derivative gains (losses) | $ | (18 | ) | $ | 1 |
| $ | 11 |
| $ | (29 | ) | $ | (9 | ) | $ | 8 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $4 million at March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
| (c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016. |
For the definitive agreement to a wholly-owned, indirect subsidiarythree months ended March 31, 2017 and 2016, the pre-tax effects of Southern Company Gas. On September 1, 2016,energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments 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) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (11 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Interest rate derivatives | 1 |
| | (190 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (3 | ) |
| Foreign currency derivatives | (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | (14 | ) | | $ | (190 | ) | | | $ | 2 |
| | $ | (4 | ) |
| Gulf Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | — |
| | (5 | ) | | Interest expense, net of amounts capitalized | — |
| | — |
|
| Total | $ | (1 | ) | | $ | (5 | ) | | | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (8 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Foreign currency derivatives | (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | (12 | ) | | $ | — |
| | | $ | 7 |
| | $ | (1 | ) |
| |
| (*) | 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 the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For Southern Company Gas, completed the acquisitionpre-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 for a purchase pricethe three months ended March 31, 2017 and the predecessor period of approximately $1.4 billion. The investmentJanuary 1, 2016 through March 31, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | 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 | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 | | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | (2 | ) | | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | — |
|
| Interest rate derivatives | — |
| | | (45 | ) | | Interest expense, net of amounts capitalized | — |
| | | 1 |
|
| Total | $ | (2 | ) | | | $ | (45 | ) | | | $ | — |
| | | $ | 1 |
|
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:
|
| | | | | | | | |
| | | Gain (Loss) |
| | | Three Months Ended
March 31, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | $ | — |
|
| | Cost of natural gas | (3 | ) | | — |
|
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | $ | — |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the three months ended March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| | | Gain (Loss) |
| | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | | (in millions) | | | (in millions) |
| Southern Company Gas | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | | $ | 20 |
|
| | Cost of natural gas | (3 | ) | | | (1 | ) |
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | | $ | 19 |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the successor three months ended March 31, 2017 and $3 million for the predecessor three months ended March 31, 2016. |
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three months ended March 31, 2017 and 2016, 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) |
| | | Three Months Ended March 31, |
| Derivative Category | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (8 | ) | | $ | 20 |
|
| Georgia Power | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | 14 |
|
For the three months ended March 31, 2017 and 2016, 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.
There was no material ineffectiveness recorded in SNG is accountedearnings for using the equity method.
Acquisition of Remaining Interest in SouthStar
SouthStar is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. At September 30, 2016, Southern Company Gas had an 85% ownership interest in SouthStar, with Piedmont owning the remaining 15%. Subsequent to September 30, 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStarany registrant for $160 million. Beginning in the fourth quarter 2016, SouthStar will be fully consolidated with Southern Company Gas.any period presented.
Southern Power
Southern Power's effective tax (benefit) rate was (385.9)% for the three months ended March 31, 2017 compared to (84.0)% for the corresponding period in 2016. The effective tax rate decrease was primarily due to additional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by a decrease in tax benefits from ITCs.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Unrecognized Tax Benefits
See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes during the three months ended March 31, 2017 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2016 | $ | 465 |
| | $ | 17 |
| | $ | 484 |
|
| Tax positions from current periods | 3 |
| | 1 |
| | 9 |
|
| Tax positions from prior periods | — |
| | — |
| | 7 |
|
| Balance as of March 31, 2017 | $ | 468 |
| | $ | 18 |
| | $ | 500 |
|
The tax positions from current and prior periods primarily relate to state tax benefits and charitable contribution carryforwards that will be impacted as a result of the proposed settlement of research and experimental (R&E) expenditures associated with the Kemper IGCC. 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 effective tax rate, if recognized, is as follows:
|
| | | | | | | | | | | | | | | |
| | As of March 31, 2017 | | As of December 31, 2016 |
| | Mississippi Power | | Southern Power | | Southern Company | | Southern Company |
| | (in millions) |
| Tax positions impacting the effective tax rate | $ | 4 |
| | $ | 18 |
| | $ | 36 |
| | $ | 20 |
|
| Tax positions not impacting the effective tax rate | 464 |
| | — |
| | 464 |
| | 464 |
|
| Balance of unrecognized tax benefits | $ | 468 |
| | $ | 18 |
| | $ | 500 |
| | $ | 484 |
|
The tax positions impacting the effective tax rate primarily relate to federal deferred income tax credits and Southern Company's estimate of the uncertainty related to the amount of those benefits, and state tax benefits and charitable contribution carryforwards that will be impacted as a result of the proposed settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are not able to be recognized due to a federal audit adjustment in the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $98 million.
Accrued interest for all tax positions other than the Section 174 R&E deductions was immaterial for all periods presented.
All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued 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 and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. See "Section 174 Research and Experimental Deduction" herein for more information.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition, the pre-Merger Southern Company Gas 2014 federal tax
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
return is 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 reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of $32 million as of March 31, 2017. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are 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 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 (C) 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.
Energy-Related Derivatives
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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 the 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 of Southern Company Gas 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 Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of 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 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 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 March 31, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date 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 for derivatives not designated as hedges, were as follows:
|
| | | | | |
| | Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| | (in millions) | | | | |
Southern Company(*) | 503 | | 2021 | | 2024 |
| Alabama Power | 71 | | 2020 | | — |
| Georgia Power | 155 | | 2020 | | — |
| Gulf Power | 42 | | 2020 | | — |
| Mississippi Power | 37 | | 2021 | | — |
| Southern Power | 21 | | 2017 | | 2017 |
Southern Company Gas(*) | 177 | | 2019 | | 2024 |
| |
| (*) | Southern Company's and Southern Company Gas' derivative instruments include 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. Southern Company Gas' volume represents the net of long natural gas positions of 3.4 billion mmBtu and short natural gas positions of 3.2 billion mmBtu as of March 31, 2017, which is also included in Southern Company's total volume. |
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 10 million mmBtu for Southern Company, 4 million mmbtu for Georgia Power, 3 million mmBtu for Southern Power, and 1 million mmBtu for each of Alabama Power, Gulf Power, and Mississippi Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2018 are $10 million for Southern Power and immaterial for all other registrants.
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 March 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) at March 31, 2017 |
| | (in millions) | | | | | | (in millions) |
| Cash Flow Hedges of Forecasted Debt | | | | | | |
| Gulf Power | $ | 80 |
| | 3-month
LIBOR | 2.32% | December 2026 | | $ | — |
|
| Cash Flow Hedges of Existing Debt | | | | | | |
| Mississippi Power | 900 |
| | 1-month
LIBOR | 0.79% | March 2018 | | 4 |
|
| Fair Value Hedges of Existing Debt | | | | | | |
Southern Company(*) | 250 |
| | 1.30% | 3-month
LIBOR + 0.17% | August 2017 | | — |
|
Southern Company(*) | 300 |
| | 2.75% | 3-month
LIBOR + 0.92% | June 2020 | | 1 |
|
Southern Company(*) | 1,500 |
| | 2.35% | 1-month
LIBOR + 0.87% | July 2021 | | (21 | ) |
| Georgia Power | 250 |
| | 5.40% | 3-month
LIBOR + 4.02% | June 2018 | | — |
|
| Georgia Power | 500 |
| | 1.95% | 3-month
LIBOR + 0.76% | December 2018 | | (3 | ) |
| Georgia Power | 200 |
| | 4.25% | 3-month
LIBOR + 2.46% | December 2019 | | 1 |
|
| Southern Company Consolidated | $ | 3,980 |
| | | | | | $ | (18 | ) |
| |
| (*) | Represents the Southern Company parent entity. |
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 March 31, 2018 are immaterial for all registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Company and certain subsidiaries have deferred gains and losses 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.
At March 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 March 31, 2017 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (35 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (27 | ) |
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (62 | ) |
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 March 31, 2018 are $24 million for Southern Company and Southern Power.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 48 |
| $ | 30 |
| $ | 73 |
| $ | 27 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 6 |
| 38 |
| 25 |
| 33 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 54 |
| $ | 68 |
| $ | 98 |
| $ | 60 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 14 |
| $ | 5 |
| $ | 23 |
| $ | 7 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | 13 |
| — |
| 12 |
| 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 32 |
| 1 |
| 28 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 27 |
| $ | 99 |
| $ | 36 |
| $ | 94 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | $ | 306 |
| $ | 271 |
| $ | 489 |
| $ | 483 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Liabilities from risk management activities, net of collateral | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 438 |
| $ | 385 |
| $ | 556 |
| $ | 564 |
|
| Gross amounts recognized | $ | 519 |
| $ | 552 |
| $ | 690 |
| $ | 718 |
|
Gross amounts offset(*) | $ | (303 | ) | $ | (395 | ) | $ | (462 | ) | $ | (524 | ) |
| Net amounts recognized in the Balance Sheets | $ | 216 |
| $ | 157 |
| $ | 228 |
| $ | 194 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Alabama Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 9 |
| $ | 5 |
| $ | 13 |
| $ | 5 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 2 |
| 5 |
| 7 |
| 4 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts recognized | $ | 11 |
| $ | 10 |
| $ | 20 |
| $ | 9 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 4 |
| $ | 12 |
| $ | 1 |
|
| | | | | |
| Georgia Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 20 |
| $ | 2 |
| $ | 30 |
| $ | 1 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| 11 |
| 14 |
| 7 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 24 |
| $ | 13 |
| $ | 44 |
| $ | 8 |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | — |
| $ | 2 |
| $ | — |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 4 |
| — |
| 3 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 4 |
| $ | 2 |
| $ | 3 |
|
| Gross amounts recognized | $ | 26 |
| $ | 17 |
| $ | 46 |
| $ | 11 |
|
| Gross amounts offset | $ | (6 | ) | $ | (6 | ) | $ | (8 | ) | $ | (8 | ) |
| Net amounts recognized in the Balance Sheets | $ | 20 |
| $ | 11 |
| $ | 38 |
| $ | 3 |
|
| | | | | |
| Gulf Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Liabilities from risk management activities | $ | 2 |
| $ | 14 |
| $ | 4 |
| $ | 12 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 17 |
| 1 |
| 17 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts recognized | $ | 2 |
| $ | 31 |
| $ | 5 |
| $ | 29 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (4 | ) | $ | (4 | ) |
| Net amounts recognized in the Balance Sheets | $ | — |
| $ | 29 |
| $ | 1 |
| $ | 25 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Mississippi Power | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 3 |
| $ | 7 |
| $ | 2 |
| $ | 6 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 5 |
| 2 |
| 5 |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 3 |
| $ | 12 |
| $ | 4 |
| $ | 11 |
|
| 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 |
| — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 4 |
| $ | — |
| $ | 3 |
| $ | — |
|
| Gross amounts recognized | $ | 7 |
| $ | 12 |
| $ | 7 |
| $ | 11 |
|
| Gross amounts offset | $ | (2 | ) | $ | (2 | ) | $ | (3 | ) | $ | (3 | ) |
| Net amounts recognized in the Balance Sheets | $ | 5 |
| $ | 10 |
| $ | 4 |
| $ | 8 |
|
| | | | | |
| Southern Power | | | | |
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 13 |
| $ | 4 |
| $ | 18 |
| $ | 4 |
|
| Foreign currency derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| 25 |
| — |
| 25 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| 37 |
| — |
| 33 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 13 |
| $ | 66 |
| $ | 18 |
| $ | 62 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Other current assets/Other current liabilities | $ | 2 |
| $ | 1 |
| $ | 3 |
| $ | 1 |
|
| Interest rate derivatives: | | | | |
| Other current assets/Other current liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives not designated as hedging instruments | $ | 2 |
| $ | 1 |
| $ | 4 |
| $ | 1 |
|
| Gross amounts recognized | $ | 15 |
| $ | 67 |
| $ | 22 |
| $ | 63 |
|
| Gross amounts offset | $ | (3 | ) | $ | (3 | ) | $ | (5 | ) | $ | (5 | ) |
| Net amounts recognized in the Balance Sheets | $ | 12 |
| $ | 64 |
| $ | 17 |
| $ | 58 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| | As of March 31, 2017 | As of December 31, 2016 |
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| | (in millions) | (in millions) |
| | | | | |
| Southern Company Gas | | | | |
| Derivatives designated as hedging instruments for regulatory purposes | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 14 |
| $ | 2 |
| $ | 24 |
| $ | 3 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | — |
| — |
| 1 |
| — |
|
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 14 |
| $ | 2 |
| $ | 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 | $ | 1 |
| $ | 1 |
| $ | 4 |
| $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | |
| Energy-related derivatives: | | | | |
| Assets from risk management activities/Liabilities from risk management activities-current | $ | 304 |
| $ | 270 |
| $ | 486 |
| $ | 482 |
|
| Other deferred charges and assets/Other deferred credits and liabilities | 132 |
| 114 |
| 66 |
| 81 |
|
| Total derivatives not designated as hedging instruments | $ | 436 |
| $ | 384 |
| $ | 552 |
| $ | 563 |
|
| Gross amounts of recognized | $ | 451 |
| $ | 387 |
| $ | 581 |
| $ | 569 |
|
Gross amounts offset(*) | $ | (272 | ) | $ | (364 | ) | $ | (435 | ) | $ | (497 | ) |
| Net amounts recognized in the Balance Sheets | $ | 179 |
| $ | 23 |
| $ | 146 |
| $ | 72 |
|
| |
| (*) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $92 million and $62 million as of March 31, 2017 and December 31, 2016, respectively. |
At March 31, 2017 and December 31, 2016, 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:
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2017 |
Derivative Category and Balance Sheet Location | Southern Company(b) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(b) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (19 | ) | $ | (1 | ) | $ | — |
| $ | (12 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (32 | ) | (3 | ) | (7 | ) | (17 | ) | (5 | ) | — |
|
Other regulatory liabilities, current(a) | 33 |
| 5 |
| 18 |
| — |
| 1 |
| 9 |
|
| Total energy-related derivative gains (losses) | $ | (18 | ) | $ | 1 |
| $ | 11 |
| $ | (29 | ) | $ | (9 | ) | $ | 8 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $4 million at March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016 |
Derivative Category and Balance Sheet Location | Southern Company(c) | Alabama Power | Georgia Power | Gulf Power | Mississippi Power | Southern Company Gas(c) |
| | (in millions) | |
| Energy-related derivatives: | | | | | | |
| Other regulatory assets, current | $ | (16 | ) | $ | (1 | ) | $ | — |
| $ | (9 | ) | $ | (5 | ) | $ | (1 | ) |
| Other regulatory assets, deferred | (19 | ) | — |
| — |
| (16 | ) | (3 | ) | — |
|
Other regulatory liabilities, current(a) | 56 |
| 8 |
| 29 |
| 1 |
| 1 |
| 17 |
|
Other regulatory liabilities, deferred(b) | 12 |
| 4 |
| 7 |
| — |
| — |
| 1 |
|
| Total energy-related derivative gains (losses) | $ | 33 |
| $ | 11 |
| $ | 36 |
| $ | (24 | ) | $ | (7 | ) | $ | 17 |
|
| |
| (a) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
| |
| (b) | Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities. |
| |
| (c) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016. |
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments 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) |
| | Statements of Income Location | Amount |
| | 2017 | | 2016 | | | 2017 | | 2016 |
| | (in millions) | | | (in millions) |
| Southern Company | | | | | | | | |
| Energy-related derivatives | $ | (11 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Interest rate derivatives | 1 |
| | (190 | ) | | Interest expense, net of amounts capitalized | (5 | ) | | (3 | ) |
| Foreign currency derivatives | (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | (14 | ) | | $ | (190 | ) | | | $ | 2 |
| | $ | (4 | ) |
| Gulf Power | | | | | | | | |
| Energy-related derivatives | $ | (1 | ) | | $ | — |
| | Depreciation and amortization | $ | — |
| | $ | — |
|
| Interest rate derivatives | — |
| | (5 | ) | | Interest expense, net of amounts capitalized | — |
| | — |
|
| Total | $ | (1 | ) | | $ | (5 | ) | | | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | |
| Energy-related derivatives | $ | (8 | ) | | $ | — |
| | Depreciation and amortization | $ | (4 | ) | | $ | (1 | ) |
| Foreign currency derivatives | (4 | ) | | — |
| | Interest expense, net of amounts capitalized | (6 | ) | | — |
|
| | | | | | Other income (expense), net(*) | 17 |
| | — |
|
| Total | $ | (12 | ) | | $ | — |
| | | $ | 7 |
| | $ | (1 | ) |
| |
| (*) | 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 the euro-denominated notes. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For Southern Company Gas, 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 for the three months ended March 31, 2017 and the predecessor period of January 1, 2016 through March 31, 2016 were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | 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 | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 | | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | (in millions) | | | (in millions) | | | (in millions) | | | (in millions) |
| Energy-related derivatives | $ | (2 | ) | | | $ | — |
| | Cost of natural gas | $ | — |
| | | $ | — |
|
| Interest rate derivatives | — |
| | | (45 | ) | | Interest expense, net of amounts capitalized | — |
| | | 1 |
|
| Total | $ | (2 | ) | | | $ | (45 | ) | | | $ | — |
| | | $ | 1 |
|
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:
|
| | | | | | | | |
| | | Gain (Loss) |
| | | Three Months Ended
March 31, |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | $ | — |
|
| | Cost of natural gas | (3 | ) | | — |
|
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | $ | — |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the three months ended March 31, 2017. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | |
| | | Gain (Loss) |
| | | Successor | | | Predecessor |
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | | (in millions) | | | (in millions) |
| Southern Company Gas | | | | | |
| Energy Related derivatives: | Natural gas revenues(*) | $ | 50 |
| | | $ | 20 |
|
| | Cost of natural gas | (3 | ) | | | (1 | ) |
| Total derivatives in non-designated hedging relationships | $ | 47 |
| | | $ | 19 |
|
| |
| (*) | Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the successor three months ended March 31, 2017 and $3 million for the predecessor three months ended March 31, 2016. |
For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
For the three months ended March 31, 2017 and 2016, 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) |
| | | Three Months Ended March 31, |
| Derivative Category | Statements of Income Location | 2017 | | 2016 |
| | | (in millions) |
| Southern Company | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (8 | ) | | $ | 20 |
|
| Georgia Power | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | (1 | ) | | $ | 14 |
|
For the three months ended March 31, 2017 and 2016, 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.
There was no material ineffectiveness recorded in earnings for any registrant for any period presented.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do 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 March 31, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
At March 31, 2017, the fair value of derivative liabilities with contingent features was immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $11 million for Southern Company, $9 million for the traditional electric operating companies and Southern Power, and $2 million for Southern Company Gas. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
Alabama Power 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, Alabama Power may be required to post collateral. At March 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 Gas may be required to deposit cash into these accounts. At March 31, 2017, cash collateral held on deposit in broker margin accounts was $92 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas only enter 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 electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gasconducts 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 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, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 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 $1.6 billion and net income of $239 million for the three months ended March 31, 2017.
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.
|
| | | |
| | For the Three Months Ended March 31, |
| | 2016 |
Operating revenues (in millions) | $ | 5,320 |
|
Net income attributable to Southern Company (in millions) | $ | 650 |
|
| Basic EPS | $ | 0.70 |
|
| Diluted EPS | $ | 0.69 |
|
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Acquisition of PowerSecure
On May 9, 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 purchase price allocation:
|
| | | |
| PowerSecure Purchase Price | |
| | (in millions) |
| Current assets | $ | 172 |
|
| Property, plant, and equipment | 46 |
|
| Intangible assets | 101 |
|
| Goodwill | 282 |
|
| Other assets | 4 |
|
| Current liabilities | (114 | ) |
| 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 $282 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
See Note 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Acquisitions During the nineThree Months Ended March 31, 2017
During the three months ended September 30, 2016, the fair values of the assets and liabilities acquired of Desert Stateline, Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, Roserock, and Tranquillity were finalized with no changes to the fair values reported.
During 2016,March 31, 2017, in accordance with itsSouthern Power's overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and(SRP), one of Southern Renewable Energy, Inc.,Power's wholly-owned subsidiaries, acquired or contracted to acquire the projects discussed below.Bethel wind facility. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.
Table of Contents |
| | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | Location | Southern Power Percentage Ownership | Actual COD | PPA Contract Period |
| Bethel | Wind | Invenergy,
January 6, 2017 | 276 | Castro County, TX | 100 | % | | January 2017 | 12 years |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approximate Nameplate Capacity (MW) | | Location | Southern Power Percentage Ownership | Actual/Expected COD | PPA Counterparties for Plant Output | PPA Contract Period | |
| Acquisitions for the Nine Months Ended September 30, 2016 |
| Calipatria | Solar | Solar Frontier Americas Holding LLC
February 11, 2016 | 20 | | Imperial County, CA | 90 | % | | February 2016 | San Diego Gas & Electric Company | 20 years | |
| East Pecos | Solar | First Solar, Inc.
March 4, 2016 | 120 | | Pecos County, TX | 100 | % | | December 2016 | Austin Energy | 15 years | |
| Grant Plains | Wind | Apex Clean Energy Holdings, LLC
August 26, 2016 | 147 | | Grant County, OK | 100 | % | | December 2016 | Oklahoma Municipal Power Authority and Steelcase Inc. | 20 years and 12 years | (a) |
| Grant Wind | Wind | Apex Clean Energy Holdings, LLC
April 7, 2016 | 151 | | Grant County, OK | 100 | % | | April 2016 | Western Farmers, East Texas, and Northeast Texas Electric Cooperative | 20 years | |
| Henrietta | Solar | SunPower Corp.
July 1, 2016 | 102 | | Kings County, CA | 51 | % | (b) | July 2016 | Pacific Gas and Electric Company | 20 years | |
| Lamesa | Solar | RES America Developments Inc.
July 1, 2016 | 102 | | Dawson County, TX | 100 | % | | First quarter 2017 | City of Garland, Texas | 15 years | |
| Passadumkeag | Wind | Quantum Utility Generation, LLC
June 30, 2016 | 42 | | Penobscot County, ME | 100 | % | | July 2016 | Western Massachusetts Electric Company | 15 years | |
| Rutherford | Solar | Cypress Creek Renewables, LLC
July 1, 2016 | 74 | | Rutherford County, NC | 90 | % | | December 2016 | Duke Energy Carolinas, LLC | 15 years | |
| Acquisitions Subsequent to September 30, 2016 |
| Mankato | Natural Gas | Calpine Corporation October 26, 2016 | 375 | (c) | Mankato, MN | 100 | % | | N/A(c) | Northern States Power Company | 10 years | |
| Wake Wind | Wind | Invenergy Wind Global LLC October 26, 2016 | 257 | | Floyd and Crosby Counties, TX | 90.1 | % | | October 2016 | Equinix Enterprises, Inc. and Owens Corning | 12 years | |
| |
(a) | In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd. |
| |
(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 federal tax benefits with respect to the transaction. |
| |
(c) | The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development. |
Acquisitions During the Nine Months Ended September 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million, which includes $145 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria and Rutherford, SunPower Corp's 49% ownership interest in Henrietta, and the assumption of $217 million in
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
construction debt (non-recourse to Southern Power), the total aggregate purchase price is approximately $923 million for the project facilities acquired during the nine months ended September 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $1.0 billion as CWIP, $58 million as property, plant, and equipment, $77 million as an intangible asset, $24 million as other assets, and $5 million as accounts payable; however, the allocations of the purchase price to individual assets have 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 $1 million in 2016 and $4 million per year thereafter. For East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million. The ultimate outcome of these matters cannot be determined at this time.
Acquisitions Subsequent to September 30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. Including the minority owner Invenergy Wind Global LLC's 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $924 million.
As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.
Acquisition Agreements Executed but Not Yet Closed
During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:
51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;
100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and
100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.
The ultimate outcome of these matters cannot be determined at this time.
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016Bethel facility included in theSouthern Power's condensed consolidated statements of income for year-to-date 2016during the first quarter 2017 is $14$4 million. The aggregate amount of net income, excluding impacts of ITCs andfrom PTCs, attributable torecognized by Southern Power related to the project facilities acquired during the ninethree months ended September 30, 2016March 31, 2017 included in theSouthern Power's condensed consolidated statements of income iswas immaterial. These businessesThe Bethel facility did not have operating revenues or activities prior to completion of construction and theirthe assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016, and for the comparable 20152016 period is not meaningful and has been omitted.
In connection with 2016 acquisitions, subsequent to March 31, 2017, allocations of the purchase price to individual assets were finalized with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Passadumkeag, and Wake Wind.
Construction Projects Completed and in Progress
During the ninethree months ended September 30, 2016,March 31, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016,March 31, 2017, total costs of construction incurred for the followingthese three projects were $3.0 billion,$401 million, of which $1.2 billion remains$203 million remained in CWIP. IncludingCWIP for the total construction costs incurred through September 30, 2016
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Lamesa and the acquisition prices allocated to CWIP, totalMankato facilities acquired in 2016. Total aggregate construction costs, forexcluding the following projectsacquisition costs, are estimatedexpected to be $3.1 billion$530 million to $3.2 billion.$590 million for these two facilities that were under construction at March 31, 2017. The ultimate outcome of these matters cannot be determined at this time.
|
| | | | | | |
SolarProject Facility | SellerResource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Counterparties for Plant Output | PPA Contract Period |
ProjectsProject Completed During the NineThree Months Ended September 30, 2016March 31, 2017 |
Butler Solar FarmEast Pecos | Strata Solar Development, LLC | 22120 | TaylorPecos County, GATX | February 2016March 2017 | Georgia Power(a)
| 2015 years |
Desert Stateline(b)
| First Solar Development, LLC | 299(c)
| San Bernardino County, CA | Through July 2016 | Southern California Edison Company (SCE) | 20 years |
Garland A | Recurrent Energy, LLC | 20 | Kern County, CA | August 2016 | SCE | 20 years |
Pawpaw | Longview Solar, LLC | 30 | Taylor County, GA | March 2016 | Georgia Power(a)
| 30 years |
Tranquillity | Recurrent Energy, LLC | 205 | Fresno County, CA | July 2016 | Shell Energy North America (US), LP/SCE | 18 years |
Projects Under Construction as of September 30, 2016March 31, 2017 |
ButlerLamesa | CERSM, LLC and Community Energy, Inc.Solar | 103102 | TaylorDawson County, GATX | December 2016 | Georgia Power(a)
| 30 years |
Garland | Recurrent Energy, LLC | 185 | Kern County, CA | October 2016 | SCEApril 2017 | 15 years |
RoserockMankato | Recurrent Energy, LLCNatural Gas | 160345 | Pecos County, TXMankato, MN | November 2016 | Austin EnergySecond quarter 2019 | 20 years |
Sandhills | N/A | 146 | Taylor County, GA | October 2016 | Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations | 25 years |
Development Projects
In December 2016, as part of Southern Power's renewable development strategy, SRP entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.
| |
(a)(J) | Affiliate PPA approved by the FERC. |
| |
(b) | On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are 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.JOINT OWNERSHIP AGREEMENTS |
(c) The facility has a totalSouthern Company Gas
See Note 4 to the financial statements of 299 MWs,Southern Company Gas in Item 8 of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(J)Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of March 31, 2017 and December 31, 2016 and related income from those investments for the successor period ended March 31, 2017 and the predecessor period ended March 31, 2016 were as follows:
|
| | | | | | |
| | | |
| Balance Sheet Information | March 31, 2017 | December 31, 2016 |
| | (in millions) |
| SNG | $ | 1,430 |
| $ | 1,394 |
|
| Triton | 44 |
| 44 |
|
| Horizon Pipeline | 31 |
| 30 |
|
| PennEast Pipeline | 30 |
| 22 |
|
| Atlantic Coast Pipeline | 42 |
| 33 |
|
| Pivotal JAX LNG, LLC | 26 |
| 16 |
|
| Other | 1 |
| 2 |
|
| Total | $ | 1,604 |
| $ | 1,541 |
|
|
| | | | | | | | |
| | Successor | | | Predecessor |
| Income Statement Information | Three Months Ended March 31, 2017 | | | Three Months Ended March 31, 2016 |
| | (in millions) | | | (in millions) |
| SNG | $ | 34 |
| | | $ | — |
|
| Horizon Pipeline | 1 |
| | | 1 |
|
| PennEast Pipeline | 3 |
| | | — |
|
| Atlantic Coast Pipeline | 1 |
| | | — |
|
| Total | $ | 39 |
| | | $ | 1 |
|
Southern Natural Gas
In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the first quarter 2017 is as follows:
|
| | | |
| Income Statement Information | Three Months Ended March 31, 2017 |
| | (in millions) |
| Revenues | $ | 155 |
|
| Operating income | $ | 84 |
|
| Net income | $ | 66 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(K) SEGMENT AND RELATED INFORMATION
Southern Company
The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and as a result of closing the Merger, 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 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 is an energy services holding company whose primary business is the distribution ofdistributes natural gas through the seven 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 $110 million and $313$100 million for the three and nine months ended September 30, 2016, respectively,March 31, 2017 and $104 million and $303$97 million for the three and nine months ended September 30, 2015, respectively.March 31, 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 productsproviding energy technologies and services in the areas of distributed generation, energy efficiency,to electric utilities and utility infrastructure,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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and nine months ended September 30,March 31, 2017 and 2016 and 2015 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
Three Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 5,236 |
| $ | 500 |
| $ | (117 | ) | $ | 5,619 |
| $ | 543 |
| $ | 139 |
| $ | (37 | ) | $ | 6,264 |
|
Segment net income (loss)(a)(b) | 1,018 |
| 176 |
| — |
| 1,194 |
| 4 |
| (67 | ) | (1 | ) | 1,130 |
|
Nine Months Ended
September 30, 2016: | | | | | | | | |
| Operating revenues | $ | 13,120 |
| $ | 1,189 |
| $ | (330 | ) | $ | 13,979 |
| $ | 543 |
| $ | 311 |
| $ | (118 | ) | $ | 14,715 |
|
Segment net income (loss)(a)(c) | 2,076 |
| 315 |
| — |
| 2,391 |
| 4 |
| (161 | ) | (8 | ) | 2,226 |
|
| Total assets at September 30, 2016 | $ | 71,448 |
| $ | 12,351 |
| $ | (440 | ) | $ | 83,359 |
| $ | 21,185 |
| $ | 2,974 |
| $ | (1,156 | ) | $ | 106,362 |
|
Three Months Ended
September 30, 2015: | | | | | | | | |
| Operating revenues | $ | 5,098 |
| $ | 401 |
| $ | (109 | ) | $ | 5,390 |
| $ | — |
| $ | 37 |
| $ | (26 | ) | $ | 5,401 |
|
Segment net income (loss)(a)(b) | 874 |
| 102 |
| — |
| 976 |
| — |
| (18 | ) | 1 |
| 959 |
|
Nine Months Ended
September 30, 2015: | | | | | | | | |
| Operating revenues | $ | 13,123 |
| $ | 1,086 |
| $ | (322 | ) | $ | 13,887 |
| $ | — |
| $ | 120 |
| $ | (86 | ) | $ | 13,921 |
|
Segment net income (loss)(a)(c) | 1,912 |
| 181 |
| — |
| 2,093 |
| — |
| 3 |
| — |
| 2,096 |
|
| Total assets at December 31, 2015 | $ | 69,052 |
| $ | 8,905 |
| $ | (397 | ) | $ | 77,560 |
| $ | — |
| $ | 1,819 |
| $ | (1,061 | ) | $ | 78,318 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | |
| | Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| | (in millions) |
Three Months Ended
March 31, 2017: | | | | | | | | |
| Operating revenues | $ | 3,786 |
| $ | 450 |
| $ | (105 | ) | $ | 4,131 |
| $ | 1,560 |
| $ | 123 |
| $ | (43 | ) | $ | 5,771 |
|
Segment net income (loss)(a)(b)(c) | 432 |
| 70 |
| — |
| 502 |
| 239 |
| (84 | ) | 1 |
| 658 |
|
| Total assets at March 31, 2017 | $ | 72,692 |
| $ | 14,681 |
| $ | (306 | ) | $ | 87,067 |
| $ | 21,683 |
| $ | 2,574 |
| $ | (1,564 | ) | $ | 109,760 |
|
Three Months Ended
March 31, 2016: | | | | | | | | |
| Operating revenues | $ | 3,769 |
| $ | 315 |
| $ | (103 | ) | $ | 3,981 |
| $ | — |
| $ | 47 |
| $ | (36 | ) | $ | 3,992 |
|
Segment net income (loss)(a)(b) | 465 |
| 50 |
| — |
| 515 |
| — |
| (23 | ) | (3 | ) | 489 |
|
| Total assets at December 31, 2016 | $ | 72,141 |
| $ | 15,169 |
| $ | (316 | ) | $ | 86,994 |
| $ | 21,853 |
| $ | 2,474 |
| $ | (1,624 | ) | $ | 109,697 |
|
| |
| (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 $88$108 million ($5467 million after tax) and $150$53 million ($9333 million after tax) for the three months ended September 30,March 31, 2017 and 2016, and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. |
(c) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $222 million ($137 million after tax) and $182 million ($112 million after tax) for the nine months ended September 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate | |
| (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) for the three months ended March 31, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Products and Services
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended September 30, 2016 | | $ | 4,808 |
| | $ | 613 |
| | $ | 198 |
| | $ | 5,619 |
|
| Three Months Ended September 30, 2015 | | 4,701 |
| | 520 |
| | 169 |
| | 5,390 |
|
| | | | | | | | | |
| Nine Months Ended September 30, 2016 | | $ | 11,932 |
| | $ | 1,455 |
| | $ | 592 |
| | $ | 13,979 |
|
| Nine Months Ended September 30, 2015 | | 11,958 |
| | 1,435 |
| | 494 |
| | 13,887 |
|
|
| | | | | | | | | | | | | | | | |
| | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) |
| Three Months Ended March 31, 2017 | | $ | 3,394 |
| | $ | 531 |
| | $ | 206 |
| | $ | 4,131 |
|
| Three Months Ended March 31, 2016 | | 3,377 |
| | 396 |
| | 208 |
| | 3,981 |
|
|
| | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | Other | Total |
| | (in millions) |
| Three Months Ended March 31, 2017 | $ | 1,132 |
| $ | 288 |
| $ | 140 |
| $ | 1,560 |
|
Southern Company Gas
Southern Company Gas 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.
Gas distribution operations is the largest component of ContentsSouthern Company Gas' 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 Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities. Gas midstream operations primarily consists of Southern Company 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, Southern Company Gas changed its segment performance measure to net income. In order to properly assess net income by segment, Southern Company Gas executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor period, Southern Company Gas is unable to provide the comparable net income.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Business segment financial data for the successor period January 1, 2017 through March 31, 2017 and the predecessor period January 1, 2016 through March 31, 2016 was as follows:
|
| | | | | | | | | | | | |
| | Southern Company Gas' Revenues |
| Period | Gas
Distribution
Operations | Gas
Marketing
Services | All Other | Total |
| | (in millions) |
| Three and Nine Months Ended September 30, 2016 | $ | 420 |
| $ | 126 |
| $ | (3 | ) | $ | 543 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Gas Distribution Operations | Gas Marketing Services | Wholesale Gas Services(*) | Gas Midstream Operations | Total | All Other | Eliminations | Consolidated |
| | (in millions) |
Successor – January 1, 2017
through March 31, 2017: | | | | | | | | |
| Operating revenues | $ | 1,180 |
| $ | 288 |
| $ | 131 |
| $ | 25 |
| $ | 1,624 |
| $ | 2 |
| $ | (66 | ) | $ | 1,560 |
|
| Segment net income | 117 |
| 31 |
| 68 |
| 15 |
| 231 |
| 8 |
| — |
| 239 |
|
Successor – Total assets at
March 31, 2017 | $ | 18,201 |
| $ | 2,118 |
| $ | 1,018 |
| $ | 2,363 |
| $ | 23,700 |
| $ | 10,860 |
| $ | (12,877 | ) | $ | 21,683 |
|
Predecessor – January 1, 2016
through March 31, 2016: | | | | | | | | |
| Operating revenues | $ | 1,028 |
| $ | 286 |
| $ | 63 |
| $ | 15 |
| $ | 1,392 |
| $ | 2 |
| $ | (60 | ) | $ | 1,334 |
|
| Segment EBIT | 235 |
| 80 |
| 44 |
| (1 | ) | 358 |
| (5 | ) | (1 | ) | 352 |
|
Successor – Total assets at
December 31, 2016 | $ | 19,453 |
| $ | 2,084 |
| $ | 1,127 |
| $ | 2,211 |
| $ | 24,875 |
| $ | 11,145 |
| $ | (14,167 | ) | $ | 21,853 |
|
| |
| (*) | 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 – January 1, 2017 through March 31, 2017 | $ | 1,839 |
| | $ | 136 |
| | $ | 1,975 |
| | $ | 1,844 |
| | $ | 131 |
|
| Predecessor – January 1, 2016 through March 31, 2016 | $ | 1,443 |
| | $ | 81 |
| | $ | 1,524 |
| | $ | 1,461 |
| | $ | 63 |
|
PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
WithThe bankruptcy filing of Westinghouse and WECTEC is expected to have a material impact on the construction cost and schedule of Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.
See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing), as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor Corporation (Fluor), which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the engineering, procurement, and construction agreement with the Contractor (the Vogtle 3 and 4 Agreement), and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Merger, Southern Company now owns Southern Company Gas, a company whose subsidiaries ownInterim Assessment Agreement; and operate a natural gas business.(vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.
Southern Company Gas
A number of subcontractors to the Contractor, including Fluor Enterprises, Inc. (Fluor Enterprises), have alleged non-payment by the 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, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is an energy services holding company whose primary business isevaluating remedies available to the distributionVogtle Owners for these payments, including draws under the $920 million of natural gas through natural gas distribution utilities. Southern Company Gas is involved in several other businesses that are mainly relatedletters of credit delivered by Westinghouse (Westinghouse Letters of Credit) and complementaryenforcement of the Toshiba Guarantee.
The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to its primary business including: gas marketing services includingfulfill the provision of natural gas commodityschedule and related services to customers in competitive markets or markets that provide for customer choice, wholesale gas services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and gas midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, Southern Company is nowcertain performance guarantees, each subject to risksan aggregate cap of 10% of the contract price, or approximately $920 million. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which it was not previously subject and Southern Company stockholdersreflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be adversely affected byrequired in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these risks. These risks include the following:
Transporting and storing natural gas involves risks that mayassessments 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 injuryestimated incremental costs to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.
Southern Company Gas' natural gas business faces increasing competition. The natural gas business is highly competitive and increasingly complex. Southern Company Gas is facing increasing competition from other companiescomplete, including owners' costs, that supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies.
Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedgematerially exceed the value of the contract can cause volatilityToshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in reportedthe event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's
and Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net income whilecost to the positionsVogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.
The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.
Item 5. Other Information.
On April 28, 2017, the Board of Directors of Gulf Power approved certain amendments to Section 7 of Gulf Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are open duefull-time executive employees of Gulf Power, Southern Company, or its affiliates, to mark-to-market accounting.no more than 12 years unless otherwise determined by the Board of Directors.
On May 1, 2017, the Board of Directors of Mississippi Power approved certain amendments to Section 2.02 of Mississippi Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are full-time executive employees of Mississippi Power, Southern Company, or its affiliates, to no more than 12 years unless otherwise determined by the Board of Directors.
Item 6. Exhibits.
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.
|
| | | | |
| | | (3) Articles of Incorporation and By-Laws |
| | | | | |
| | | GeorgiaGulf Power |
| | | | | |
| | * | (a)1(d) | | By-Laws of GeorgiaGulf Power, as amended, effective August 17, 2016. (Designated in Form 8-K dated August 17, 2016, File No. 1-6468, as Exhibit 3.1.)July 1, 2017. |
| | | | | |
| | | Mississippi Power |
| | | |
| | * | (a)1(e) | | By-Laws of Mississippi Power, as amended, effective October 25, 2016. (Designated in Form 8-K dated October 25, 2016, File No. 001-11229, as Exhibit 3.1.) |
|
| | | | July 1, 2017. |
| | | |
| | | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | | |
| | | Southern CompanyAlabama Power |
| | | | | |
| | | (a)1(b) | - | SecondFifty-Sixth Supplemental Indenture to Junior SubordinatedSenior Note Indenture, dated as of September 15, 2016,March 3, 2017, providing for the issuance of the Series 2016A 5.25% Junior Subordinated2017A 2.45% Senior Notes due October 1, 2076.March 30, 2022. (Designated in Form 8-K dated September 12, 2016,February 27, 2017, File No. 1-3526,1-3164, as Exhibit 4.4.4.6.) |
| | | | |
| | Georgia Power |
| | |
| | (c)1 | - | Fifty-Sixth Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017A 2.00% Senior Notes due March 30, 2020. (Designated in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(a).) |
| | | | |
| | (c)2 | - | Fifty-Seventh Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017B 3.25% Senior Notes due March 30, 2027. (Designated in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(b).) |
| | | | |
|
| | | | |
| | (10) Material Contracts |
| | | | | |
| | | Southern PowerCompany |
| | | | |
| # | * | (a)1 | - | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. |
| | | | |
| # | * | (a)2 | - | Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. |
| | | | |
| # | * | (a)3 | - | Letter Agreement among Southern Company Gas, Southern Company, and Andrew W. Evans and Performance Stock Unit Award Agreement, dated September 29, 2016. |
| | | | |
| # | * | (a)4 | - | Form of Time-Vesting Restricted Stock Unit Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. |
| | | | |
| # | | (a)5 | - | Nonqualified Savings Plan as amended and restated as of January 1, 2009, First Amendment effective December 18, 2009, Second Amendment effective January 1, 2013, and Third Amendment effective January 1, 2013. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-14174, as Exhibit 10.1.av and in Form 10-K for the year ended December 31, 2013, File No. 1-14174, as Exhibits 10.1.aa, 10.1.ab, and 10.1.ac.) |
| | | | |
| # | | (a)6 | - | Excess Benefit Plan as amended and restated as of January 1, 2009. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-14174, as Exhibit 10.1.az.) |
| | | | |
| | * | (f)Alabama Power |
| | | | |
| # | | (b)1 | - | Twelfth Supplemental Indenture to Senior Note Indenture, dated asForm of September 7, 2016.Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein. |
| | | | |
| # | | (b)2 | - | 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)2 herein. |
| | | | |
| | Georgia Power |
| | | | |
| # | | (c)1 | - | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein. |
| | | | |
| # | | (c)2 | - | 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)2 herein. |
| | | | | |
| | * | (f)(c)3 | - | Interim 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, WECTEC Staffing Services LLC, and WECTEC. |
| | | | |
| * | (c)4 | - | Amendment No. 1 to Interim 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, WECTEC Staffing Services LLC, and WECTEC. |
| | | | |
| | Gulf Power |
| | | | |
| # | | (d)1 | - | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein. |
| | | | |
|
| | | | |
| # | | (d)2 | - | Thirteenth Supplemental IndentureForm of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein. |
| | | | |
| | Mississippi Power |
| | | | |
| # | | (e)1 | - | Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein. |
| | | | |
| # | | (e)2 | - | 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)2 herein. |
| | | | |
| * | (e)3 | - | Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and Southern Company in the aggregate principal amount of up to Senior$375,000,000. |
| | | | |
| * | (e)4 | - | Second Amended and Restated Promissory Note Indenture, dated asFebruary 28, 2017 between Mississippi Power and Southern Company in the aggregate principal amount of September 20, 2016, providing for$301,126,146.39. |
| | | | |
| * | (e)5 | - | Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and Southern Company in the issuanceaggregate principal amount of the Series 2016C 2.75% Senior Notes due September 20, 2023.up to $275,000,000. |
| | | | | |
| | | (24) Power of Attorney and Resolutions |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-3526 as Exhibit 24(a).) |
| | | | | |
| | | Alabama Power |
| | | | | |
| | | (b)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-3164 as Exhibit 24(b).) |
| | | | | |
| | | Georgia Power |
| | | | | |
| | | (c)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 1-6468 as Exhibit 24(c).) |
| | | | | |
| | | Gulf Power |
| | | | | |
| | | (d)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 001-31737 as Exhibit 24(d).) |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 001-11229 as Exhibit 24(e)1.) |
| | | | |
| | (e)2 | - | Power of Attorney for Anthony L. Wilson. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)2..) |
| | | | | |
| | | Southern Power |
| | | | | |
| | | (f)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 333-98553001-37803 as Exhibit 24(f)1..) |
| | | | | |
| | | (f)2Southern Company Gas |
| | | | |
| | (g) | - | Power of Attorney for Joseph A. Miller.and resolution. (Designated in the Form 10-K for the year ended December 31, 2015,2016, File No. 333-985531-14174 as Exhibit 24(f)2.24(g).) |
| | | | | |
|
| | | | |
| | | (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)1 | - | Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (d)2 | - | Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e)1 | - | Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (e)2 | - | Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f)1 | - | Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | * | (f)2 | - | Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Company Gas |
| | | | |
| * | (g)1 | - | Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | |
| * | (g)2 | - | Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | | |
|
| | | | |
| | (32) Section 906 Certifications |
| | | | | |
| | | Southern Company |
| | | | | |
| | * | (a) | - | Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Alabama Power |
| | | | | |
| | * | (b) | - | Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Georgia Power |
| | | | | |
| | * | (c) | - | Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
|
| | | | |
| | | Gulf Power |
| | | | | |
| | * | (d) | - | Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | * | (e) | - | Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Power |
| | | | | |
| | * | (f) | - | Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | | |
| | | Southern Company Gas |
| | | | |
| * | (g) | - | Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002. |
| | | | |
| | (101) Interactive Data Files |
| | | | | |
| | * | 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 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 included in such company's report.
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| | | |
| | | THE SOUTHERN COMPANY |
| | | | |
| By | | Thomas A. Fanning |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Art P. Beattie |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016May 2, 2017
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | | ALABAMA POWER COMPANY |
| | | | |
| By | | Mark A. Crosswhite | |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Philip C. Raymond |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | | GEORGIA POWER COMPANY |
| | | | |
| By | | W. Paul Bowers |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | W. Ron Hinson |
| | | Executive Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
GULF POWER COMPANY
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | | GULF POWER COMPANY |
| | | | |
| By | | S. W. Connally, Jr. |
| | | Chairman, President and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Xia Liu |
| | | Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | | MISSISSIPPI POWER COMPANY |
| | | | |
| By | | Anthony L. Wilson |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Moses H. Feagin |
| | | Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | | SOUTHERN POWER COMPANY |
| | | | |
| By | | Joseph A. Miller |
| | | Chairman, President, and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | William C. Grantham |
| | | Senior Vice President, Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/ Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: November 4, 2016May 2, 2017
SOUTHERN COMPANY GAS
SIGNATURES
Pursuant to the requirements 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 included in such company's report.
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| | | |
| | SOUTHERN COMPANY GAS |
| | | |
| By | | Andrew W. Evans |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
| By | | Elizabeth W. Reese |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
| By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: May 2, 2017