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 June 30, 20152016
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 |
| | | | | |
| 001-11229 | | Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211 | | 64-0205820 |
| | | | | |
333-98553001-37803 | | Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000 | | 58-2598670 |
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. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting 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 |
| The Southern Company | | X | | | | | | |
| Alabama Power Company | | | | | | X | | |
| Georgia Power Company | | | | | | X | | |
| Gulf Power Company | | | | | | X | | |
| Mississippi Power Company | | | | | | X | | |
| Southern Power Company | | | | | | X | | |
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 June 30, 20152016 |
|
| The Southern Company | | Par Value $5 Per Share | | 908,424,808941,598,673 |
|
| 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 | | 5,642,717 |
|
| Mississippi Power Company | | Without Par Value | | 1,121,000 |
|
| Southern Power Company | | Par Value $0.01 Per Share | | 1,000 |
|
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. 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
June 30, 20152016
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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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INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 20152016
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| | | Page Number |
| | | |
| Item 1. | | |
| Item 1A. | | |
| Item 2. | | Inapplicable |
| Item 3. | Defaults Upon Senior Securities | Inapplicable |
| Item 4. | Mine Safety Disclosures | Inapplicable |
| Item 5. | Other Information | Inapplicable |
| Item 6. | | |
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DEFINITIONS
|
| |
| Term | Meaning |
| | |
| 2012 MPSC CPCN Order | A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing 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 |
ASCASU | Accounting Standards CodificationUpdate |
| 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 Air Act | Clean Air Act Amendments of 1990 |
Contractor | Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.), a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. |
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 |
| 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, and Southern Power for the year ended December 31, 20142015 |
| GAAP | GenerallyU.S. generally accepted accounting principles |
| Georgia Power | Georgia Power Company |
| Gulf Power | Gulf Power Company |
| IGCC | Integrated coal gasification combined cycle |
| IIC | Intercompany interchange contract |
| 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 |
| KWH | Kilowatt-hour |
| LIBOR | London Interbank Offered Rate |
| MATS rule | Mercury and Air Toxics Standards rule |
| Merger | The merger of Merger Sub with and into Southern Company Gas on the terms and subject to the conditions set forth in the Merger Agreement, with Southern Company Gas continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company |
DEFINITIONS
(continued)
|
| |
| Term | Meaning |
| |
| Merger Agreement | Agreement and Plan of Merger, dated August 23, 2015, among Southern Company, Southern Company Gas, and Merger Sub |
| Merger Sub | AMS Corp., a wholly-owned, direct subsidiary of Southern Company |
| Mirror CWIP | A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers |
| Mississippi Power | Mississippi Power Company |
| mmBtu | Million British thermal units |
| Moody's | Moody's Investors Service, Inc. |
| MW | Megawatt |
DEFINITIONS
(continued)
|
| |
Term | Meaning |
| |
| NCCR | Georgia Power's Nuclear Construction Cost Recovery |
| NRC | U.S. Nuclear Regulatory Commission |
| OCI | Other comprehensive income |
| PEP | Mississippi Power's Performance Evaluation Plan |
| Plant Vogtle Units 3 and 4 | Two new nuclear generating units under construction at Georgia Power's Plant Vogtle |
| power pool | The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations |
| PPA | Power purchase agreementagreements and contracts for differences that provide the owner of the renewable facility a certain fixed price for the electricity sold to the grid |
| PSC | Public Service Commission |
| PTC | Production tax credit |
| Rate CNP | Alabama Power's Rate Certificated New Plant |
| Rate CNP Compliance | Alabama Power's Rate Certificated New Plant Compliance |
Rate CNP Environmental | Alabama Power's Rate Certificated New Plant Environmental |
Rate CNP PPA | Alabama Power's Rate Certificated New Plant Power Purchase Agreement |
| Rate RSE | Alabama Power's Rate Stabilization and Equalization plan |
| registrants | Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company |
| ROE | Return on equity |
| S&P | Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, 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 |
| Southern Company | The Southern Company |
| Southern Company Gas | Southern Company Gas (formerly known as AGL Resources Inc.) |
| Southern Company system | Southern Company, the traditional electric operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, Southern Company Services, Inc. (the Southern Company system service company),SCS, Southern Communications Services, Inc., and other subsidiaries as of June 30, 2016 |
| Southern Nuclear | Southern Nuclear Operating Company, Inc. |
| Southern Power | Southern Power Company and its subsidiaries |
| traditional electric operating companies | Alabama Power, Georgia Power, Gulf Power, and Mississippi Power |
| 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 |
| 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 retail rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources, filings with state and federal regulatory authorities, 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:
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• | the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, CCR, and emissions of sulfur, nitrogen, CO2, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, 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 pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and 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, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of fuels;
effects of inflation;
the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction 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 and related legal proceedings involving the commercial parties;
actions related to cost recovery for the Kemper IGCC, including actions relating to Mississippi PSC approval of a rate recovery plan, including Mississippi Power's request for interim rates, proposed securitization, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, and satisfaction of requirements to utilize ITCs and grants;
the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;
Mississippi PSC review of the prudence of Kemper IGCC costs;
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
(continued)This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail 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, 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, implementing such decision, and any further related legal or regulatory proceedings;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
(continued)
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 or Southern Company Gas' 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 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 subsidiaries to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;
catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business or Southern Company Gas' 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 June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 3,714 |
| | $ | 3,770 |
| | $ | 7,256 |
| | $ | 7,628 |
| $ | 3,748 |
| | $ | 3,714 |
| | $ | 7,124 |
| | $ | 7,256 |
|
| Wholesale revenues | 448 |
| | 515 |
| | 915 |
| | 1,119 |
| 446 |
| | 448 |
| | 842 |
| | 915 |
|
| Other electric revenues | 162 |
| | 169 |
| | 325 |
| | 334 |
| 166 |
| | 162 |
| | 348 |
| | 325 |
|
| Other revenues | 13 |
| | 13 |
| | 24 |
| | 30 |
| 99 |
| | 13 |
| | 137 |
| | 24 |
|
| Total operating revenues | 4,337 |
| | 4,467 |
| | 8,520 |
| | 9,111 |
| 4,459 |
| | 4,337 |
| | 8,451 |
| | 8,520 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 1,200 |
| | 1,462 |
| | 2,412 |
| | 3,109 |
| 1,023 |
| | 1,200 |
| | 1,934 |
| | 2,412 |
|
| Purchased power | 171 |
| | 133 |
| | 315 |
| | 320 |
| 189 |
| | 171 |
| | 354 |
| | 315 |
|
| Cost of sales | | 58 |
| | — |
| | 77 |
| | — |
|
| Other operations and maintenance | 1,100 |
| | 1,019 |
| | 2,222 |
| | 2,005 |
| 1,099 |
| | 1,100 |
| | 2,206 |
| | 2,222 |
|
| Depreciation and amortization | 500 |
| | 504 |
| | 987 |
| | 1,001 |
| 569 |
| | 500 |
| | 1,110 |
| | 987 |
|
| Taxes other than income taxes | 245 |
| | 246 |
| | 497 |
| | 493 |
| 255 |
| | 245 |
| | 511 |
| | 497 |
|
| Estimated loss on Kemper IGCC | 23 |
| | — |
| | 32 |
| | 380 |
| 81 |
| | 23 |
| | 134 |
| | 32 |
|
| Total operating expenses | 3,239 |
| | 3,364 |
| | 6,465 |
| | 7,308 |
| 3,274 |
| | 3,239 |
| | 6,326 |
| | 6,465 |
|
| Operating Income | 1,098 |
| | 1,103 |
| | 2,055 |
| | 1,803 |
| 1,185 |
| | 1,098 |
| | 2,125 |
| | 2,055 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 39 |
| | 62 |
| | 102 |
| | 119 |
| 45 |
| | 39 |
| | 98 |
| | 102 |
|
| Interest expense, net of amounts capitalized | (180 | ) | | (210 | ) | | (393 | ) | | (416 | ) | (293 | ) | | (180 | ) | | (539 | ) | | (393 | ) |
| Other income (expense), net | (12 | ) | | (6 | ) | | (19 | ) | | (13 | ) | (29 | ) | | (12 | ) | | (57 | ) | | (19 | ) |
| Total other income and (expense) | (153 | ) | | (154 | ) | | (310 | ) | | (310 | ) | (277 | ) | | (153 | ) | | (498 | ) | | (310 | ) |
| Earnings Before Income Taxes | 945 |
| | 949 |
| | 1,745 |
| | 1,493 |
| 908 |
| | 945 |
| | 1,627 |
| | 1,745 |
|
| Income taxes | 302 |
| | 321 |
| | 576 |
| | 497 |
| 272 |
| | 302 |
| | 494 |
| | 576 |
|
| Consolidated Net Income | 643 |
| | 628 |
| | 1,169 |
| | 996 |
| 636 |
| | 643 |
| | 1,133 |
| | 1,169 |
|
| Less: | | | | | | | | |
| Dividends on Preferred and Preference Stock of Subsidiaries | 14 |
| | 17 |
| | 31 |
| | 34 |
| 12 |
| | 14 |
| | 23 |
| | 31 |
|
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries | $ | 629 |
| | $ | 611 |
| | $ | 1,138 |
| | $ | 962 |
| |
| Net income attributable to noncontrolling interests | | 12 |
| | — |
| | 13 |
| | — |
|
| Consolidated Net Income Attributable to Southern Company | | $ | 612 |
| | $ | 629 |
| | $ | 1,097 |
| | $ | 1,138 |
|
| Common Stock Data: | | | | | | | | | | | | | | |
| Earnings per share (EPS) — | | | | | | | | | | | | | | |
| Basic EPS | $ | 0.69 |
| | $ | 0.68 |
| | $ | 1.25 |
| | $ | 1.08 |
| $ | 0.65 |
| | $ | 0.69 |
| | $ | 1.19 |
| | $ | 1.25 |
|
| Diluted EPS | $ | 0.69 |
| | $ | 0.68 |
| | $ | 1.25 |
| | $ | 1.07 |
| $ | 0.65 |
| | $ | 0.69 |
| | $ | 1.18 |
| | $ | 1.25 |
|
| Average number of shares of common stock outstanding (in millions) | | | | | | | | | | | | | | |
| Basic | 909 |
| | 895 |
| | 910 |
| | 892 |
| 934 |
| | 909 |
| | 925 |
| | 910 |
|
| Diluted | 912 |
| | 899 |
| | 914 |
| | 896 |
| 940 |
| | 912 |
| | 931 |
| | 914 |
|
| Cash dividends paid per share of common stock | $ | 0.5425 |
| | $ | 0.5250 |
| | $ | 1.0675 |
| | $ | 1.0325 |
| $ | 0.5600 |
| | $ | 0.5425 |
| | $ | 1.1025 |
| | $ | 1.0675 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Consolidated Net Income | $ | 643 |
| | $ | 628 |
| | $ | 1,169 |
| | $ | 996 |
| $ | 636 |
| | $ | 643 |
| | $ | 1,133 |
| | $ | 1,169 |
|
| Other comprehensive income (loss): | | | | | | | | | | | | | | |
| Qualifying hedges: | | | | | | | | | | | | | | |
| Changes in fair value, net of tax of $12, $-, $1, and $-, respectively | 19 |
| | — |
| | 1 |
| | — |
| |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $-, $2, and $2, respectively | 2 |
| | 1 |
| | 3 |
| | 2 |
| |
Changes in fair value, net of tax of $(13), $12, $(85), and $1,
respectively | | (20 | ) | | 19 |
| | (137 | ) | | 1 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $10, $1, $11, and $2, respectively | | 16 |
| | 2 |
| | 18 |
| | 3 |
|
| Pension and other post retirement benefit plans: | | | | | | | | | | | | | | |
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $2, and $1, respectively | 1 |
| | 1 |
| | 3 |
| | 2 |
| |
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $2, respectively | | 1 |
| | 1 |
| | 2 |
| | 3 |
|
| Total other comprehensive income (loss) | 22 |
| | 2 |
| | 7 |
| | 4 |
| (3 | ) | | 22 |
| | (117 | ) | | 7 |
|
| Less: | | | | | | | | |
| Dividends on preferred and preference stock of subsidiaries | (14 | ) | | (17 | ) | | (31 | ) | | (34 | ) | 12 |
| | 14 |
| | 23 |
| | 31 |
|
| Comprehensive Income | $ | 651 |
| | $ | 613 |
| | $ | 1,145 |
| | $ | 966 |
| |
| Comprehensive income attributable to noncontrolling interests | | 12 |
| | — |
| | 13 |
| | — |
|
Consolidated Comprehensive Income Attributable to Southern Company | | $ | 609 |
| | $ | 651 |
| | $ | 980 |
| | $ | 1,145 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | |
| | For the Six Months
Ended June 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Consolidated net income | $ | 1,169 |
| | $ | 996 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 1,171 |
| | 1,182 |
|
| Deferred income taxes | 783 |
| | 46 |
|
| Allowance for equity funds used during construction | (102 | ) | | (119 | ) |
| Stock based compensation expense | 66 |
| | 40 |
|
| Estimated loss on Kemper IGCC | 32 |
| | 380 |
|
| Income taxes receivable, non-current | (444 | ) | | — |
|
| Other, net | (6 | ) | | 23 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (158 | ) | | (579 | ) |
| -Fossil fuel stock | 136 |
| | 419 |
|
| -Materials and supplies | (21 | ) | | (20 | ) |
| -Other current assets | (78 | ) | | (88 | ) |
| -Accounts payable | (311 | ) | | (231 | ) |
| -Accrued taxes | (60 | ) | | 72 |
|
| -Accrued compensation | (269 | ) | �� | (40 | ) |
| -Mirror CWIP | 82 |
| | 67 |
|
| -Other current liabilities | 117 |
| | (78 | ) |
| Net cash provided from operating activities | 2,107 |
| | 2,070 |
|
| Investing Activities: | | | |
| Property additions | (2,647 | ) | | (2,692 | ) |
| Nuclear decommissioning trust fund purchases | (933 | ) | | (445 | ) |
| Nuclear decommissioning trust fund sales | 928 |
| | 443 |
|
| Cost of removal, net of salvage | (87 | ) | | (54 | ) |
| Change in construction payables, net | 56 |
| | 89 |
|
| Prepaid long-term service agreement | (110 | ) | | (93 | ) |
| Other investing activities | 27 |
| | (17 | ) |
| Net cash used for investing activities | (2,766 | ) | | (2,769 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 184 |
| | 339 |
|
| Proceeds — | | | |
| Long-term debt issuances | 3,075 |
| | 1,314 |
|
| Interest-bearing refundable deposit | — |
| | 75 |
|
| Common stock issuances | 116 |
| | 318 |
|
| Short-term borrowings | 320 |
| | — |
|
| Redemptions and repurchases— | | | |
| Long-term debt | (939 | ) | | (431 | ) |
| Interest-bearing refundable deposits | (275 | ) | | — |
|
| Preferred and preference stock | (412 | ) | | — |
|
| Common stock | (115 | ) | | (5 | ) |
| Short-term borrowings | (250 | ) | | — |
|
| Payment of common stock dividends | (972 | ) | | (920 | ) |
| Payment of dividends on preferred and preference stock of subsidiaries | (36 | ) | | (34 | ) |
| Other financing activities | 66 |
| | (33 | ) |
| Net cash provided from financing activities | 762 |
| | 623 |
|
| Net Change in Cash and Cash Equivalents | 103 |
| | (76 | ) |
| Cash and Cash Equivalents at Beginning of Period | 710 |
| | 659 |
|
| Cash and Cash Equivalents at End of Period | $ | 813 |
| | $ | 583 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for -- | | | |
| Interest (net of $57 and $47 capitalized for 2015 and 2014, respectively) | $ | 374 |
| | $ | 365 |
|
| Income taxes, net | (16 | ) | | 212 |
|
| Noncash transactions — Accrued property additions at end of period | 345 |
| | 509 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Assets | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 813 |
| | $ | 710 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 1,312 |
| | 1,090 |
|
| Unbilled revenues | | 579 |
| | 432 |
|
| Under recovered regulatory clause revenues | | 173 |
| | 136 |
|
| Other accounts and notes receivable | | 209 |
| | 307 |
|
| Accumulated provision for uncollectible accounts | | (17 | ) | | (18 | ) |
| Fossil fuel stock, at average cost | | 795 |
| | 930 |
|
| Materials and supplies, at average cost | | 1,043 |
| | 1,039 |
|
| Vacation pay | | 177 |
| | 177 |
|
| Prepaid expenses | | 564 |
| | 665 |
|
| Deferred income taxes, current | | 499 |
| | 506 |
|
| Other regulatory assets, current | | 382 |
| | 346 |
|
| Other current assets | | 76 |
| | 50 |
|
| Total current assets | | 6,605 |
| | 6,370 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 71,462 |
| | 70,013 |
|
| Less accumulated depreciation | | 23,918 |
| | 24,059 |
|
| Plant in service, net of depreciation | | 47,544 |
| | 45,954 |
|
| Other utility plant, net | | 87 |
| | 211 |
|
| Nuclear fuel, at amortized cost | | 889 |
| | 911 |
|
| Construction work in progress | | 8,487 |
| | 7,792 |
|
| Total property, plant, and equipment | | 57,007 |
| | 54,868 |
|
| Other Property and Investments: | | | | |
| Nuclear decommissioning trusts, at fair value | | 1,572 |
| | 1,546 |
|
| Leveraged leases | | 751 |
| | 743 |
|
| Miscellaneous property and investments | | 232 |
| | 203 |
|
| Total other property and investments | | 2,555 |
| | 2,492 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 1,533 |
| | 1,510 |
|
| Unamortized debt issuance expense | | 208 |
| | 202 |
|
| Unamortized loss on reacquired debt | | 234 |
| | 243 |
|
| Other regulatory assets, deferred | | 4,763 |
| | 4,334 |
|
| Income taxes receivable, non-current | | 444 |
| | — |
|
| Other deferred charges and assets | | 832 |
| | 904 |
|
| Total deferred charges and other assets | | 8,014 |
| | 7,193 |
|
| Total Assets | | $ | 74,181 |
| | $ | 70,923 |
|
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Consolidated net income | $ | 1,133 |
| | $ | 1,169 |
|
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 1,306 |
| | 1,171 |
|
| Deferred income taxes | 279 |
| | 783 |
|
| Allowance for equity funds used during construction | (98 | ) | | (102 | ) |
| Stock based compensation expense | 69 |
| | 66 |
|
| Hedge settlements | (201 | ) | | (3 | ) |
| Estimated loss on Kemper IGCC | 134 |
| | 32 |
|
| Income taxes receivable, non-current | — |
| | (444 | ) |
| Other, net | (69 | ) | | (3 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (197 | ) | | (158 | ) |
| -Fossil fuel stock | 70 |
| | 136 |
|
| -Other current assets | (53 | ) | | (99 | ) |
| -Accounts payable | (71 | ) | | (311 | ) |
| -Accrued taxes | 74 |
| | (60 | ) |
| -Accrued compensation | (222 | ) | | (269 | ) |
| -Mirror CWIP | — |
| | 82 |
|
| -Other current liabilities | (39 | ) | | 117 |
|
| Net cash provided from operating activities | 2,115 |
| | 2,107 |
|
| Investing Activities: | | | |
| Business acquisitions, net of cash acquired | (897 | ) | | (408 | ) |
| Property additions | (3,486 | ) | | (2,239 | ) |
| Investment in restricted cash | (8,608 | ) | | — |
|
| Distribution of restricted cash | 649 |
| | — |
|
| Nuclear decommissioning trust fund purchases | (585 | ) | | (933 | ) |
| Nuclear decommissioning trust fund sales | 580 |
| | 928 |
|
| Cost of removal, net of salvage | (99 | ) | | (87 | ) |
| Change in construction payables, net | (260 | ) | | 56 |
|
| Prepaid long-term service agreement | (82 | ) | | (110 | ) |
| Other investing activities | 113 |
| | 27 |
|
| Net cash used for investing activities | (12,675 | ) | | (2,766 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 471 |
| | 184 |
|
| Proceeds — | | | |
| Long-term debt issuances | 12,038 |
| | 3,075 |
|
| Common stock issuances | 1,383 |
| | 116 |
|
| Short-term borrowings | — |
| | 320 |
|
| Redemptions and repurchases — | | | |
| Long-term debt | (1,272 | ) | | (939 | ) |
| Interest-bearing refundable deposits | — |
| | (275 | ) |
| Preferred and preference stock | — |
| | (412 | ) |
| Common stock repurchased | — |
| | (115 | ) |
| Short-term borrowings | (475 | ) | | (250 | ) |
| Distributions to noncontrolling interests | (11 | ) | | (1 | ) |
| Capital contributions from noncontrolling interests | 179 |
| | 78 |
|
| Purchase of membership interests from noncontrolling interests | (129 | ) | | — |
|
| Payment of common stock dividends | (1,023 | ) | | (972 | ) |
| Other financing activities | (108 | ) | | (47 | ) |
| Net cash provided from financing activities | 11,053 |
| | 762 |
|
| Net Change in Cash and Cash Equivalents | 493 |
| | 103 |
|
| Cash and Cash Equivalents at Beginning of Period | 1,404 |
| | 710 |
|
| Cash and Cash Equivalents at End of Period | $ | 1,897 |
| | $ | 813 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $61 and $57 capitalized for 2016 and 2015, respectively) | $ | 458 |
| | $ | 374 |
|
| Income taxes, net | (138 | ) | | (16 | ) |
| Noncash transactions — Accrued property additions at end of period | 549 |
| | 345 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 3,643 |
| | $ | 3,333 |
|
| Interest-bearing refundable deposits | | — |
| | 275 |
|
| Notes payable | | 1,057 |
| | 803 |
|
| Accounts payable | | 1,395 |
| | 1,593 |
|
| Customer deposits | | 398 |
| | 390 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 12 |
| | 151 |
|
| Other accrued taxes | | 391 |
| | 487 |
|
| Accrued interest | | 241 |
| | 295 |
|
| Accrued vacation pay | | 222 |
| | 223 |
|
| Accrued compensation | | 305 |
| | 576 |
|
| Mirror CWIP | | 353 |
| | 271 |
|
| Other current liabilities | | 677 |
| | 570 |
|
| Total current liabilities | | 8,694 |
| | 8,967 |
|
| Long-term Debt | | 22,674 |
| | 20,841 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 12,187 |
| | 11,568 |
|
| Deferred credits related to income taxes | | 186 |
| | 192 |
|
| Accumulated deferred investment tax credits | | 1,290 |
| | 1,208 |
|
| Employee benefit obligations | | 2,375 |
| | 2,432 |
|
| Asset retirement obligations | | 2,860 |
| | 2,168 |
|
| Other cost of removal obligations | | 1,206 |
| | 1,215 |
|
| Other regulatory liabilities, deferred | | 408 |
| | 398 |
|
| Other deferred credits and liabilities | | 996 |
| | 594 |
|
| Total deferred credits and other liabilities | | 21,508 |
| | 19,775 |
|
| Total Liabilities | | 52,876 |
| | 49,583 |
|
| Redeemable Preferred Stock of Subsidiaries | | 118 |
| | 375 |
|
| Redeemable Noncontrolling Interest | | 41 |
| | 39 |
|
| Stockholders' Equity: | | | | |
| Common Stockholders' Equity: | | | | |
| Common stock, par value $5 per share — | | | | |
| Authorized — 1.5 billion shares | | | | |
| Issued — June 30, 2015: 912 million shares | | | | |
| — December 31, 2014: 909 million shares | | | | |
| Treasury — June 30, 2015: 3.3 million shares | | | | |
| — December 31, 2014: 0.7 million shares | | | | |
| Par value | | 4,555 |
| | 4,539 |
|
| Paid-in capital | | 6,123 |
| | 5,955 |
|
| Treasury, at cost | | (142 | ) | | (26 | ) |
| Retained earnings | | 9,767 |
| | 9,609 |
|
| Accumulated other comprehensive loss | | (121 | ) | | (128 | ) |
| Total Common Stockholders' Equity | | 20,182 |
| | 19,949 |
|
| Preferred and Preference Stock of Subsidiaries | | 609 |
| | 756 |
|
| Noncontrolling Interest | | 355 |
| | 221 |
|
| Total Stockholders' Equity | | 21,146 |
| | 20,926 |
|
| Total Liabilities and Stockholders' Equity | | $ | 74,181 |
| | $ | 70,923 |
|
|
| | | | | | | | |
| Assets | | At June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 1,897 |
| | $ | 1,404 |
|
| Restricted cash and cash equivalents | | 7,963 |
| | — |
|
| Receivables — | | | | |
| Customer accounts receivable | | 1,281 |
| | 1,058 |
|
| Unbilled revenues | | 590 |
| | 397 |
|
| Under recovered regulatory clause revenues | | 12 |
| | 63 |
|
| Income taxes receivable, current | | — |
| | 144 |
|
| Other accounts and notes receivable | | 247 |
| | 398 |
|
| Accumulated provision for uncollectible accounts | | (14 | ) | | (13 | ) |
| Fossil fuel stock, at average cost | | 798 |
| | 868 |
|
| Materials and supplies, at average cost | | 1,210 |
| | 1,061 |
|
| Vacation pay | | 181 |
| | 178 |
|
| Prepaid expenses | | 563 |
| | 495 |
|
| Other regulatory assets, current | | 350 |
| | 402 |
|
| Other current assets | | 71 |
| | 71 |
|
| Total current assets | | 15,149 |
| | 6,526 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 78,112 |
| | 75,118 |
|
| Less accumulated depreciation | | 24,778 |
| | 24,253 |
|
| Plant in service, net of depreciation | | 53,334 |
| | 50,865 |
|
| Other utility plant, net | | 174 |
| | 233 |
|
| Nuclear fuel, at amortized cost | | 934 |
| | 934 |
|
| Construction work in progress | | 9,451 |
| | 9,082 |
|
| Total property, plant, and equipment | | 63,893 |
| | 61,114 |
|
| Other Property and Investments: | | | | |
| Nuclear decommissioning trusts, at fair value | | 1,578 |
| | 1,512 |
|
| Leveraged leases | | 763 |
| | 755 |
|
| Goodwill | | 264 |
| | 2 |
|
Other intangible assets, net of amortization of $14 and $12
at June 30, 2016 and December 31, 2015, respectively | | 490 |
| | 317 |
|
| Miscellaneous property and investments | | 230 |
| | 166 |
|
| Total other property and investments | | 3,325 |
| | 2,752 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 1,580 |
| | 1,560 |
|
| Unamortized loss on reacquired debt | | 220 |
| | 227 |
|
| Other regulatory assets, deferred | | 5,460 |
| | 4,989 |
|
| Income taxes receivable, non-current | | 413 |
| | 413 |
|
| Other deferred charges and assets | | 833 |
| | 737 |
|
| Total deferred charges and other assets | | 8,506 |
| | 7,926 |
|
| Total Assets | | $ | 90,873 |
| | $ | 78,318 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholders' Equity | | At June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 2,724 |
| | $ | 2,674 |
|
| Notes payable | | 1,372 |
| | 1,376 |
|
| Accounts payable | | 1,493 |
| | 1,905 |
|
| Customer deposits | | 408 |
| | 404 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 13 |
| | 19 |
|
| Other accrued taxes | | 398 |
| | 484 |
|
| Accrued interest | | 289 |
| | 249 |
|
| Accrued vacation pay | | 229 |
| | 228 |
|
| Accrued compensation | | 335 |
| | 549 |
|
| Asset retirement obligations, current | | 349 |
| | 217 |
|
| Liabilities from risk management activities | | 95 |
| | 156 |
|
| Other regulatory liabilities, current | | 115 |
| | 278 |
|
| Other current liabilities | | 694 |
| | 590 |
|
| Total current liabilities | | 8,514 |
| | 9,129 |
|
| Long-term Debt | | 35,368 |
| | 24,688 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 12,563 |
| | 12,322 |
|
| Deferred credits related to income taxes | | 183 |
| | 187 |
|
| Accumulated deferred investment tax credits | | 1,427 |
| | 1,219 |
|
| Employee benefit obligations | | 2,485 |
| | 2,582 |
|
| Asset retirement obligations, deferred | | 4,129 |
| | 3,542 |
|
| Unrecognized tax benefits | | 380 |
| | 370 |
|
| Other cost of removal obligations | | 1,154 |
| | 1,162 |
|
| Other regulatory liabilities, deferred | | 335 |
| | 254 |
|
| Other deferred credits and liabilities | | 724 |
| | 720 |
|
| Total deferred credits and other liabilities | | 23,380 |
| | 22,358 |
|
| Total Liabilities | | 67,262 |
| | 56,175 |
|
| Redeemable Preferred Stock of Subsidiaries | | 118 |
| | 118 |
|
| Redeemable Noncontrolling Interests | | 47 |
| | 43 |
|
| Stockholders' Equity: | | | | |
| Common Stockholders' Equity: | | | | |
| Common stock, par value $5 per share — | | | | |
| Authorized — 1.5 billion shares | | | | |
| Issued — June 30, 2016: 942 million shares | | | | |
| — December 31, 2015: 915 million shares | | | | |
| Treasury — June 30, 2016: 0.8 million shares | | | | |
| — December 31, 2015: 3.4 million shares | | | | |
| Par value | | 4,708 |
| | 4,572 |
|
| Paid-in capital | | 7,499 |
| | 6,282 |
|
| Treasury, at cost | | (30 | ) | | (142 | ) |
| Retained earnings | | 10,085 |
| | 10,010 |
|
| Accumulated other comprehensive loss | | (247 | ) | | (130 | ) |
| Total Common Stockholders' Equity | | 22,015 |
| | 20,592 |
|
| Preferred and Preference Stock of Subsidiaries | | 609 |
| | 609 |
|
| Noncontrolling Interests | | 822 |
| | 781 |
|
| Total Stockholders' Equity | | 23,446 |
| | 21,982 |
|
| Total Liabilities and Stockholders' Equity | | $ | 90,873 |
| | $ | 78,318 |
|
The accompanying notes as they relate to Southern Company are an integral part of these consolidated financial statements.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and Southern Power Company and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business as of June 30, 2016 of electricity sales by the traditional electric operating companies and Southern Power. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company's other business activities include providing products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects and telecommunications.projects. For additional information on these businesses, see BUSINESS – "The Southern Company System – Traditional Operating Companies," " – Southern Power," and " – Other Businesses" in Item 1 of the Form 10-K.
In addition, constructionMerger 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.
Prior to the completion of the Merger on July 1, 2016, Southern Company and Southern Company Gas operated as separate companies. Accordingly, except for specific references to the Merger, the discussion and analysis of results of operations and financial condition as of and for the three and six months ended June 30, 2016 set forth herein relate solely to Southern Company and do not include Southern Company Gas. Following the Merger, the results of operations and financial condition of Southern Company Gas will be consolidated with those of Southern Company. The descriptions herein of strategy and outlook and the risks and challenges Southern Company faces include Southern Company Gas, to the extent material. 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 six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.
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"Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction"Construction Program," and Note (B) to the Condensed Financial Statements under "Retail"Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" and "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information. 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, 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 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $18 | | 2.9 | | $176 | | 18.3 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.7) | | $(41) | | (3.6) |
Consolidated net income attributable to Southern Company'sCompany was $612 million ($0.65 per share) for the second quarter 2015 net income after dividends on preferred and preference stock of subsidiaries was2016 compared to $629 million ($0.69 per share) compared to $611 million ($0.68 per share) for the second quarter 2014. The increase was primarily due to an increase in retail revenues resulting from retail base rate increases and warmer weather in the second quarter 2015 as compared to the corresponding period in 2014, partially offset by the correction of an error affecting billings to certain Georgia Power commercial and industrial customers. Also contributing to the increase were state income tax benefits realized and a decrease in interest expense. The increase in2015. For year-to-date 2016, consolidated net income attributable to Southern Company was partially offset by increases in non-fuel operations and maintenance expenses and a decrease in AFUDC equity.
Southern Company's year-to-date 2015 net income after dividends on preferred and preference stock of subsidiaries was $1.1$1.10 billion ($1.251.19 per share) compared to $962 million$1.14 billion ($1.081.25 per share) for the corresponding period in 2014. The increase was2015. These decreases were primarily the result of lower pre-taxhigher interest expenses, higher depreciation and amortization, and higher charges of $32 million ($20 million after tax) recorded in 2015 comparedrelated to a pre-tax charge of $380 million ($235 million after tax) recorded in the corresponding period in 2014 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. These decreases were partially offset by increases in retail revenues resulting from retail base rate increases as well as the 2015 correction of a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power. Also contributing to the year-to-date 2016 decrease was lower retail revenues due to milder weather compared to the corresponding period in 2015.
Retail Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $34 | | 0.9 | | $(132) | | (1.8) |
In the second quarter 2016, retail revenues were $3.75 billioncompared to $3.71 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $7.1 billion compared to $7.3 billion for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 3,714 |
| | | | $ | 7,256 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 186 |
| | 5.0 |
| | 296 |
| | 4.1 |
|
| Sales growth (decline) | (18 | ) | | (0.5 | ) | | 4 |
| | 0.1 |
|
| Weather | (2 | ) | | (0.1 | ) | | (87 | ) | | (1.2 | ) |
| Fuel and other cost recovery | (132 | ) | | (3.5 | ) | | (345 | ) | | (4.8 | ) |
| Retail – current year | $ | 3,748 |
| | 0.9 | % | | $ | 7,124 |
| | (1.8 | )% |
Revenues associated with changes in rates and pricing increased in the second 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. The increase in rates and pricing was also due to the 2015 correction of a Georgia Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
IGCC, as well as an increase in retail base rates. The increase in net income was partially offset by increases in non-fuel operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(56) | | (1.5) | | $(372) | | (4.9) |
In the second quarter 2015, retail revenues were $3.7 billion compared to $3.8 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $7.3 billion compared to $7.6 billion for the corresponding period in 2014.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2015 | | Year-to-Date 2015 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 3,770 |
| | | | $ | 7,628 |
| | |
| Estimated change resulting from – | | | | | | | | |
| Rates and pricing | | 30 |
| | 0.8 |
| | 107 |
| | 1.4 |
|
| Sales growth | | 23 |
| | 0.6 |
| | 41 |
| | 0.5 |
|
| Weather | | 46 |
| | 1.2 |
| | 8 |
| | 0.1 |
|
| Fuel and other cost recovery | | (155 | ) | | (4.1 | ) | | (528 | ) | | (6.9 | ) |
| Retail – current year | | $ | 3,714 |
| | (1.5 | )% | | $ | 7,256 |
| | (4.9 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2015 when compared to the corresponding periods in 2014 primarily due to increased revenues at Alabama Power associated with an increase in rates under rate stabilization and equalization (Rate RSE) and at Georgia Power related to base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, all effective January 1, 2015. The increase was partially offset by the correction of anbilling error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowingand the implementation of rates for variable demand-driven pricingcertain Kemper IGCC in-service assets at GeorgiaMississippi Power.
See Note (A) to the Condensed Financial Statements herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power,– Rate RSE" and" "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 increaseddecreased in the second quarter 20152016 when compared to the corresponding period in 2014.2015. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased 1.2%decreased 0.2% and 0.7%1.9%, respectively, in the second quarter 2015, both as a result of2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales increased 0.2%decreased 1.9% in the second quarter 20152016 primarily due to increased sales in the non-manufacturing, transportation,chemicals, primary metals, textiles, and pipeline sectors, partially offset by decreased salesincreases in the primary metals, chemicals,paper and paperlumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
Revenues attributable to changes in sales increased slightly for year-to-date 20152016 when compared to the corresponding period in 2014. Industrial KWH sales increased 1.1% for year-to-date 2015 primarily due to increased sales in the non-manufacturing, transportation, pipeline, and petroleum sectors, partially offset by decreased sales in the primary metals and chemicals sectors. Weather-adjusted commercial KWH sales increased 0.7% for year-to-date 2015 primarily due to customer growth.2015. Weather-adjusted residential KWH sales increased 0.7%0.6% for year-to-date 2015 as a result of2016 due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.5% for year-to-date 2016 primarily in the chemicals, primary metals, non-manufacturing, textiles, and pipeline sectors, partially offset by increases in the paper, stone, clay, and glass, and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
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 secondfirst quarter and year-to-date 20142015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
this adjustment, second quarter 2015year-to-date 2016 weather-adjusted residential sales increased 1.4%0.7%, weather-adjusted commercial sales increased 0.5%decreased 0.4%, and industrial KWH sales increased 0.1%decreased 1.4% as compared to the corresponding period in 2014. Also, without this adjustment, year-to-date 2015 weather-adjusted residential sales increased 0.6%, weather-adjusted commercial sales increased 0.4%, and industrial KWH sales increased 1.0% as compared to the corresponding period in 2014.2015.
Fuel and other cost recovery revenues decreased $155$132 million and $528$345 million in the second quarter and year-to-date 2015,2016, respectively, when compared to the corresponding periods in 20142015 primarily due to a decrease 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 purchased powerPPA costs, and do not affect net income. The traditional electric operating companies may alsoeach have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.PPA capacity costs.
Wholesale Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(67) | | (13.0) | | $(204) | | (18.2) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.4) | | $(73) | | (8.0) |
Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and 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 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale 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 second quarter 2015,2016, wholesale revenues were $448$446 million compared to $515$448 million for the corresponding period in 20142015. This decrease was primarily related to a $44 million decrease in energy revenues and a $23$21 million decrease in capacity revenues, partially offset by a $19 million increase in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power, and the expiration of wholesale contracts at Georgia Power. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.
For year-to-date 2015,2016, wholesale revenues were $915$842 million compared to $1.1 billion$915 million for the corresponding period in 20142015. This decrease was primarily related to a $162$64 million decrease in capacity revenues and a $9 million decrease in energy revenues and a $42 millionrevenues. The decrease in capacity revenues. The decreases in energy revenues were primarily related to lower fuel costs, partially offset by increases in energy revenues from new solar PPAs at Southern Power. The decreases in capacity revenues werewas primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, unit retirements as well as the expiration of wholesale contracts in December 2014 at Georgia Power, unit retirements at Georgia Power, and PPA expirationsthe expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power. The decrease in energy revenues was primarily due to lower fuel prices, partially offset by an increase in short-term sales and renewable energy sales at Southern Power.
See FUTURE EARNINGS POTENTIAL – "Retail 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.
Other Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $86 | | N/M | | $113 | | N/M |
N/M - Not meaningful
In the second quarter 2016, other revenues were $99 million compared to $13 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $137 million compared to $24 million for the corresponding period in 2015. These increases were primarily due to $59 million in revenues from products and services at PowerSecure International, Inc. (PowerSecure), which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, revenues from certain unregulated sales of products and services by the traditional electric operating companies of $20 million and $46 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 – Acquisition of PowerSecure International, Inc." herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
| | | | | Second Quarter 2015
vs.
Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (262 | ) | | (17.9) | | $ | (697 | ) | | (22.4) | $ | (177 | ) | | (14.8) | | $ | (478 | ) | | (19.8) |
| Purchased power | | 38 |
| | 28.6 | | (5 | ) | | (1.6) | 18 |
| | 10.5 | | 39 |
| | 12.4 |
| Total fuel and purchased power expenses | | $ | (224 | ) | | $ | (702 | ) | | $ | (159 | ) | | $ | (439 | ) | |
In the second quarter 2015,2016, total fuel and purchased power expenses were $1.4$1.2 billion compared to $1.6$1.4 billion for the corresponding period in 2014.2015. The decrease was primarily the result of a $337$159 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $113 million increase in the volume of KWHs generated and purchased primarily due to increased demand resulting from warmer weather in the second quarter 2015 as compared to the corresponding period in 2014.coal prices.
For year-to-date 2015,2016, total fuel and purchased power expenses were $2.7$2.3 billion compared to $3.4$2.7 billion for the corresponding period in 2014.2015. The decrease was primarily the result of a $792$376 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas and coal prices partially offset byand a $90$63 million increasenet decrease 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 – "Retail"Retail Regulatory Matters – Retail Fuel Cost Recovery"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.
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | Second Quarter
2015 | | Second Quarter
2014 | | Year-to-Date 2015 | | Year-to-Date 2014 | Second Quarter
2016 | | Second Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (billions of KWHs) | | 46 | | 47 | | 92 | | 94 | 45 | | 46 | | 89 | | 92 |
Total purchased power (billions of KWHs) | | 4 | | 2 | | 6 | | 5 | 4 | | 4 | | 8 | | 6 |
Sources of generation (percent) — | | |
| Coal | | 39 | | 44 | | 36 | | 45 | 32 | | 39 | | 30 | | 36 |
| Nuclear | | 15 | | 17 | | 16 | | 16 | 16 | | 15 | | 17 | | 16 |
| Gas | | 42 | | 36 | | 44 | | 35 | 48 | | 42 | | 47 | | 44 |
| Hydro | | 3 | | 3 | | 3 | | 4 | 2 | | 3 | | 4 | | 3 |
| Renewables | | 1 | | — | | 1 | | — | |
| Other Renewables | | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (cents per net KWH) — | | |
| Coal | | 3.37 | | 3.79 | | 3.52 | | 4.00 | 3.20 | | 3.37 | | 3.22 | | 3.52 |
| Nuclear | | 0.84 | | 0.89 | | 0.75 | | 0.89 | 0.82 | | 0.84 | | 0.82 | | 0.75 |
| Gas | | 2.76 | | 3.82 | | 2.73 | | 4.00 | 2.24 | | 2.76 | | 2.20 | | 2.73 |
Average cost of fuel, generated (cents per net KWH) | | 2.70 | | 3.28 | | 2.70 | | 3.46 | 2.33 | | 2.70 | | 2.28 | | 2.70 |
Average cost of purchased power (cents per net KWH)(*) | | 5.63 | | 7.41 | | 6.26 | | 8.20 | 5.03 | | 5.63 | | 5.14 | | 6.26 |
| |
| (*) | 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 second quarter 2016, fuel expense was $1.0 billion compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 19.2% decrease in the volume of KWHs generated by coal, an 18.8%
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel
In the second quarter 2015, fuel expense was $1.2 billion compared to $1.5 billion for the corresponding period in 2014. The decrease was primarily due to a 27.8% decrease in the average cost of natural gas per KWH generated, an 11.1% decrease in the average cost of coal per KWH generated, and a 10.6% decrease in the volume of KWHs generated by coal, partially offset by a 19.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2015, fuel expense was $2.4 billion compared to $3.1 billion for the corresponding period in 2014. The decrease was primarily due to a 31.8% decrease in the average cost of natural gas per KWH generated, a 21.2% decrease in the volume of KWHs generated by coal, and a 12.0%5.0% decrease in the average cost of coal per KWH generated, partially offset by a 32.3%14.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $1.9 billion compared to $2.4 billion for the corresponding period in 2015. The decrease was primarily due to a 20.4% decrease in the volume of KWHs generated by coal, a 19.4% decrease in the average cost of natural gas per KWH generated, and an 8.5% decrease in the average cost of coal per KWH generated, partially offset by a 4.6% increase in the volume of KWHs generated by natural gas.
Purchased PowerConstruction Program
InConstruction 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. 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, 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 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.7) | | $(41) | | (3.6) |
Consolidated net income attributable to Southern Company was $612 million ($0.65 per share) for the second quarter 2015, purchased power expense was $171 million2016 compared to $133$629 million ($0.69 per share) for the second quarter 2015. For year-to-date 2016, consolidated net income attributable to Southern Company was $1.10 billion ($1.19 per share) compared to $1.14 billion ($1.25 per share) for the corresponding period in 2014. The increase2015. These decreases were primarily the result of higher interest expenses, 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. These decreases were partially offset by increases in retail revenues resulting from retail base rate increases as well as the 2015 correction of a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power. Also contributing to the year-to-date 2016 decrease was primarilylower retail revenues due to a 50.0% increase in the volume of KWHs purchased primarily as a result of increased demand from warmermilder weather in the second quarter 2015 as compared to the corresponding period in 2014, partially offset by a 24.0% decrease in the average cost per KWH purchased.2015.
For year-to-date 2015, purchased power expense was $315 million compared to $320 million for the corresponding period in 2014. The decrease was primarily due to a 23.7% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices, partially offset by an 18.0% increase in the volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's 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.
Other Operations and Maintenance ExpensesRetail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $81 | | 7.9 | | $217 | | 10.8 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $34 | | 0.9 | | $(132) | | (1.8) |
In the second quarter 2015, other operations and maintenance expenses2016, retail revenues were $1.1$3.75 billioncompared to $1.0$3.71 billion for the corresponding period in 2014. The increase was primarily due to a $32 million increase in generation expenses primarily related to non-outage operations and maintenance, a $23 million increase in employee compensation and benefits including pension costs, and a $6 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, partially offset by a $7 million decrease in transmission and distribution costs primarily related to overhead line maintenance. In addition, in the second quarter 2014, Alabama Power deferred approximately $16 million of certain non-nuclear outage expenditures under an accounting order.
2015. For year-to-date 2015, other operations and maintenance expenses2016, retail revenues were $2.2$7.1 billion compared to $2.0$7.3 billion for the corresponding period in 2014. The increase was2015.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 3,714 |
| | | | $ | 7,256 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 186 |
| | 5.0 |
| | 296 |
| | 4.1 |
|
| Sales growth (decline) | (18 | ) | | (0.5 | ) | | 4 |
| | 0.1 |
|
| Weather | (2 | ) | | (0.1 | ) | | (87 | ) | | (1.2 | ) |
| Fuel and other cost recovery | (132 | ) | | (3.5 | ) | | (345 | ) | | (4.8 | ) |
| Retail – current year | $ | 3,748 |
| | 0.9 | % | | $ | 7,124 |
| | (1.8 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to a $58 millionincreases 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. The increase in employee compensationrates and benefits including pension costs,pricing was also due to the 2015 correction of a $41 million increase in generation expenses primarily relatedGeorgia Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
billing error to non-outage operationsa small number of large commercial and maintenance, a $30 million increase in scheduled outageindustrial customers and maintenance coststhe implementation of rates for certain Kemper IGCC in-service assets at generation facilities, and a $22 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs. In addition, in the first half of 2014, Alabama Power deferred approximately $41 million of certain non-nuclear outage expenditures under an accounting order.Mississippi Power.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Non-Nuclear Outage Accounting Order"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 for additional information related to non-nuclear outage expenditures. Also seeand Note (F)(B) to the Condensed Financial Statements herein for additional informationinformation.
Revenues attributable to changes in sales decreased in the second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales decreased 0.2% and 1.9%, respectively, in the second quarter 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.9% in the second quarter 2016 primarily in the chemicals, primary metals, textiles, and pipeline sectors, partially offset by increases in the paper and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
Revenues attributable to changes in sales increased slightly for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 0.6% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.5% for year-to-date 2016 primarily in the chemicals, primary metals, non-manufacturing, textiles, and pipeline sectors, partially offset by increases in the paper, stone, clay, and glass, and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
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 0.7%, weather-adjusted commercial sales decreased 0.4%, and industrial KWH sales decreased 1.4% as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues decreased $132 million and $345 million in the second 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 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 Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.4) | | $(73) | | (8.0) |
Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and 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 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale 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 second quarter 2016, wholesale revenues were $446 million compared to $448 million for the corresponding period in 2015. This decrease was primarily related to pension costs.a $21 million decrease in capacity revenues, partially offset by a $19 million increase in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power, and the expiration of wholesale contracts at Georgia Power. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.
For year-to-date 2016, wholesale revenues were $842 million compared to $915 million for the corresponding period in 2015. This decrease was primarily related to a $64 million decrease in capacity revenues and a $9 million decrease in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, unit retirements as well as the expiration of wholesale contracts at Georgia Power, and the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power. The decrease in energy revenues was primarily due to lower fuel prices, partially offset by an increase in short-term sales and renewable energy sales at Southern Power.
See FUTURE EARNINGS POTENTIAL – "Retail 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.
Other Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $86 | | N/M | | $113 | | N/M |
N/M - Not meaningful
In the second quarter 2016, other revenues were $99 million compared to $13 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $137 million compared to $24 million for the corresponding period in 2015. These increases were primarily due to $59 million in revenues from products and services at PowerSecure International, Inc. (PowerSecure), which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, revenues from certain unregulated sales of products and services by the traditional electric operating companies of $20 million and $46 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 – Acquisition of PowerSecure International, Inc." herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (177 | ) | | (14.8) | | $ | (478 | ) | | (19.8) |
| Purchased power | 18 |
| | 10.5 | | 39 |
| | 12.4 |
| Total fuel and purchased power expenses | $ | (159 | ) | | | | $ | (439 | ) | | |
In the second quarter 2016, total fuel and purchased power expenses were $1.2 billion compared to $1.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $159 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices.
For year-to-date 2016, total fuel and purchased power expenses were $2.3 billion compared to $2.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $376 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices and a $63 million net decrease 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 – "Retail Regulatory Matters – Retail 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.
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter
2016 | | Second Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (billions of KWHs) | 45 | | 46 | | 89 | | 92 |
Total purchased power (billions of KWHs) | 4 | | 4 | | 8 | | 6 |
Sources of generation (percent) — | | | | | | | |
| Coal | 32 | | 39 | | 30 | | 36 |
| Nuclear | 16 | | 15 | | 17 | | 16 |
| Gas | 48 | | 42 | | 47 | | 44 |
| Hydro | 2 | | 3 | | 4 | | 3 |
| Other Renewables | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (cents per net KWH) — | | | | | | | |
| Coal | 3.20 | | 3.37 | | 3.22 | | 3.52 |
| Nuclear | 0.82 | | 0.84 | | 0.82 | | 0.75 |
| Gas | 2.24 | | 2.76 | | 2.20 | | 2.73 |
Average cost of fuel, generated (cents per net KWH) | 2.33 | | 2.70 | | 2.28 | | 2.70 |
Average cost of purchased power (cents per net KWH)(*) | 5.03 | | 5.63 | | 5.14 | | 6.26 |
| |
| (*) | 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 second quarter 2016, fuel expense was $1.0 billion compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 19.2% decrease in the volume of KWHs generated by coal, an 18.8%
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciationdecrease in the average cost of natural gas per KWH generated, and Amortization
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(4) | | (0.8) | | $(14) | | (1.4) |
For year-to-date 2015, depreciation and amortization2016, fuel expense was $987 million$1.9 billion compared to $1.0$2.4 billion for the corresponding period in 2014.2015. The decrease was primarily due to a $49 million reduction20.4% decrease in depreciation rates at Alabama Power,the volume of KWHs generated by coal, a $14 million reduction19.4% decrease in depreciation at Gulf Power, as approved by the Florida PSC, and a $9 million reduction in otheraverage cost of removal at Georgia Power,natural gas per KWH generated, and an 8.5% decrease in the average cost of coal per KWH generated, partially offset by a $49 million4.6% increase as a result of additional plant in service at the traditional operating companies and Southern Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – 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 Case" herein for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $23 | | N/M | | $(348) | | (91.6) |
N/M – Not meaningful
In the second quarter 2015, an estimated probable loss on the Kemper IGCC of $23 million was recorded at Southern Company. For year-to-date 2015 and 2014, estimated probable losses on the Kemper IGCC of $32 million and $380 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 (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.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(23) | | (37.1) | | $(17) | | (14.3) |
In the second quarter 2015, AFUDC equity was $39 million compared to $62 million for the corresponding period in 2014. For year-to-date 2015, AFUDC equity was $102 million compared to $119 million for the corresponding period in 2014. The decreases were primarily due to Mississippi Power placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and lower AFUDC equity at Georgia Power. Additionally, for year-to-date 2015, the decrease in AFUDC equity was partially offset by environmental and transmission projects at the traditional operating companies. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (14.3) | | $(23) | | (5.5) |
In the second quarter 2015, interest expense, net of amounts capitalized was $180 million compared to $210 million in the corresponding period in 2014. For year-to-date 2015, interest expense, netvolume of amounts capitalized was $393 million compared to $416 million in the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued, partially offsetKWHs generated by an increase in outstanding long-term debt. Also contributing to the year-to-date decrease was an increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information. Also see Note (B) "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(19) | | (5.9) | | $79 | | 15.9 |
In the second quarter 2015, income taxes were $302 million compared to $321 million for the corresponding period in 2014. The decrease is primarily due to state income tax benefits realized in 2015 and increased federal income tax benefits related to ITCs in 2015 at Southern Power, partially offset by a decrease in non-taxable AFUDC equity, higher pre-tax earnings, and beneficial changes that impacted 2014 state income taxes.
For year-to-date 2015, income taxes were $576 million compared to $497 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014, beneficial changes that impacted 2014 state income taxes, and a decrease in non-taxable AFUDC equity, partially offset by otherwise lower pre-tax earnings in 2015, state income tax benefits realized in 2015, and increased federal income tax benefits related to ITCs in 2015 at Southern Power.
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 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 business of selling electricity. These factors include the traditional operating companies' 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 the completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of the competitive wholesale business and successfully expanding investments in renewable energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, 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 business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. 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.
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. 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 Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
New Source Review Actions
See Note 3 to the financial statements of Southern Company under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations," – "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order," and – "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and Mississippi Power.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule, and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, Mississippi, North Carolina, and Texas) to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016. The ultimate impact of the
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – 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 April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Southern Company recorded incremental asset retirement obligations (ARO) of approximately $700 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding these AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the final rules on the Southern Company system cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
The traditional 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 operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional 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 operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Retail Fuel Cost Recovery
The traditional 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 operating companies continuously monitor their under or over recovered fuel cost balances. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
primarily through its Rate RSE, Rate CNP, rate energy cost recovery, and natural disaster reserve rate. 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 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.
Rate CNP
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.
In April 2015, the Financial Accounting Standards Board (FASB) proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.
In accordance with an accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.
Renewable Energy
On June 25, 2015, Alabama Power filed a petition with the Alabama PSC for a Renewable Generation Certificate (RGC). The RGC would develop a process that allows Alabama Power to build its own renewable projects each less than 80 MWs or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is expected to rule on this matter in August 2015. The ultimate outcome of this matter cannot be determined at this time.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. 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.
Renewables Development
As part of the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 249 MWs of the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.
On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and energy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.
On July 21, 2015, the Georgia PSC approved Georgia Power's request to build, own, and operate a 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.
Integrated Resource Plan
To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.
Gulf Power
Renewables
On April 16, 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015, the Florida PSC approved an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements will be for energy only and will be recovered through Gulf Power's fuel cost recovery mechanism.
Mississippi Power
2015 Rate Case
On May 15, 2015 and July 10, 2015, Mississippi Power filed alternative rate proposals related to recovery of Kemper IGCC-related costs with the Mississippi PSC. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Renewables
In April and May 2015, Mississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.
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. 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, 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 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | (2.7) | | $(41) | | (3.6) |
Consolidated net income attributable to Southern Company was $612 million ($0.65 per share) for the second quarter 2016 compared to $629 million ($0.69 per share) for the second quarter 2015. For year-to-date 2016, consolidated net income attributable to Southern Company was $1.10 billion ($1.19 per share) compared to $1.14 billion ($1.25 per share) for the corresponding period in 2015. These decreases were primarily the result of higher interest expenses, 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. These decreases were partially offset by increases in retail revenues resulting from retail base rate increases as well as the 2015 correction of a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power. Also contributing to the year-to-date 2016 decrease was lower retail revenues due to milder weather compared to the corresponding period in 2015.
Retail Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $34 | | 0.9 | | $(132) | | (1.8) |
In the second quarter 2016, retail revenues were $3.75 billioncompared to $3.71 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $7.1 billion compared to $7.3 billion for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| | Second Quarter 2016 | | Year-to-Date 2016 |
| | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | $ | 3,714 |
| | | | $ | 7,256 |
| | |
| Estimated change resulting from – | | | | | | | |
| Rates and pricing | 186 |
| | 5.0 |
| | 296 |
| | 4.1 |
|
| Sales growth (decline) | (18 | ) | | (0.5 | ) | | 4 |
| | 0.1 |
|
| Weather | (2 | ) | | (0.1 | ) | | (87 | ) | | (1.2 | ) |
| Fuel and other cost recovery | (132 | ) | | (3.5 | ) | | (345 | ) | | (4.8 | ) |
| Retail – current year | $ | 3,748 |
| | 0.9 | % | | $ | 7,124 |
| | (1.8 | )% |
Revenues associated with changes in rates and pricing increased in the second 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. The increase in rates and pricing was also due to the 2015 correction of a Georgia Power
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
billing error to a small number of large commercial and industrial customers and the implementation of rates for certain Kemper IGCC in-service assets at Mississippi Power.
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 second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales decreased 0.2% and 1.9%, respectively, in the second quarter 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.9% in the second quarter 2016 primarily in the chemicals, primary metals, textiles, and pipeline sectors, partially offset by increases in the paper and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
Revenues attributable to changes in sales increased slightly for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 0.6% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.5% for year-to-date 2016 primarily in the chemicals, primary metals, non-manufacturing, textiles, and pipeline sectors, partially offset by increases in the paper, stone, clay, and glass, and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.
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 0.7%, weather-adjusted commercial sales decreased 0.4%, and industrial KWH sales decreased 1.4% as compared to the corresponding period in 2015.
Fuel and other cost recovery revenues decreased $132 million and $345 million in the second 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 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 Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (0.4) | | $(73) | | (8.0) |
Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and 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 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale 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 second quarter 2016, wholesale revenues were $446 million compared to $448 million for the corresponding period in 2015. This decrease was primarily related to a $21 million decrease in capacity revenues, partially offset by a $19 million increase in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power, and the expiration of wholesale contracts at Georgia Power. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.
For year-to-date 2016, wholesale revenues were $842 million compared to $915 million for the corresponding period in 2015. This decrease was primarily related to a $64 million decrease in capacity revenues and a $9 million decrease in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, unit retirements as well as the expiration of wholesale contracts at Georgia Power, and the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power. The decrease in energy revenues was primarily due to lower fuel prices, partially offset by an increase in short-term sales and renewable energy sales at Southern Power.
See FUTURE EARNINGS POTENTIAL – "Retail 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.
Other Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $86 | | N/M | | $113 | | N/M |
N/M - Not meaningful
In the second quarter 2016, other revenues were $99 million compared to $13 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $137 million compared to $24 million for the corresponding period in 2015. These increases were primarily due to $59 million in revenues from products and services at PowerSecure International, Inc. (PowerSecure), which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, revenues from certain unregulated sales of products and services by the traditional electric operating companies of $20 million and $46 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 – Acquisition of PowerSecure International, Inc." herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | $ | (177 | ) | | (14.8) | | $ | (478 | ) | | (19.8) |
| Purchased power | 18 |
| | 10.5 | | 39 |
| | 12.4 |
| Total fuel and purchased power expenses | $ | (159 | ) | | | | $ | (439 | ) | | |
In the second quarter 2016, total fuel and purchased power expenses were $1.2 billion compared to $1.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $159 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices.
For year-to-date 2016, total fuel and purchased power expenses were $2.3 billion compared to $2.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $376 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices and a $63 million net decrease 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 – "Retail Regulatory Matters – Retail 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.
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | | | | |
| | Second Quarter
2016 | | Second Quarter
2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (billions of KWHs) | 45 | | 46 | | 89 | | 92 |
Total purchased power (billions of KWHs) | 4 | | 4 | | 8 | | 6 |
Sources of generation (percent) — | | | | | | | |
| Coal | 32 | | 39 | | 30 | | 36 |
| Nuclear | 16 | | 15 | | 17 | | 16 |
| Gas | 48 | | 42 | | 47 | | 44 |
| Hydro | 2 | | 3 | | 4 | | 3 |
| Other Renewables | 2 | | 1 | | 2 | | 1 |
Cost of fuel, generated (cents per net KWH) — | | | | | | | |
| Coal | 3.20 | | 3.37 | | 3.22 | | 3.52 |
| Nuclear | 0.82 | | 0.84 | | 0.82 | | 0.75 |
| Gas | 2.24 | | 2.76 | | 2.20 | | 2.73 |
Average cost of fuel, generated (cents per net KWH) | 2.33 | | 2.70 | | 2.28 | | 2.70 |
Average cost of purchased power (cents per net KWH)(*) | 5.03 | | 5.63 | | 5.14 | | 6.26 |
| |
| (*) | 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 second quarter 2016, fuel expense was $1.0 billion compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 19.2% decrease in the volume of KWHs generated by coal, an 18.8%
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
decrease in the average cost of natural gas per KWH generated, and a 5.0% decrease in the average cost of coal per KWH generated, partially offset by a 14.7% increase in the volume of KWHs generated by natural gas.
For year-to-date 2016, fuel expense was $1.9 billion compared to $2.4 billion for the corresponding period in 2015. The decrease was primarily due to a 20.4% decrease in the volume of KWHs generated by coal, a 19.4% decrease in the average cost of natural gas per KWH generated, and an 8.5% decrease in the average cost of coal per KWH generated, partially offset by a 4.6% increase in the volume of KWHs generated by natural gas.
Purchased Power
In the second quarter 2016, purchased power expense was $189 million compared to $171 million for the corresponding period in 2015. The increase was primarily due to a 20.9% increase in the volume of KWHs purchased, partially offset by a 10.7% decrease in the average cost per KWH purchased, primarily as a result of lower natural gas and coal prices.
For year-to-date 2016, purchased power expense was $354 million compared to $315 million for the corresponding period in 2015. The increase was primarily due to a 33.0% increase in the volume of KWHs purchased, partially offset by a 17.9% decrease in the average cost per KWH purchased, primarily as a result of lower natural gas and coal prices.
Energy purchases will vary depending on demand for energy within the Southern Company system's 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 Sales
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $58 | | N/M | | $77 | | N/M |
N/M - Not meaningful
In the second quarter and year-to-date 2016, cost of sales were $58 million and $77 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, costs of $13 million and $32 million, respectively, related to certain unregulated sales of products and services by the traditional electric operating companies, were reclassified as cost of 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
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (0.1) | | $(16) | | (0.7) |
Other operations and maintenance expenses decreased slightly in the second quarter 2016 as compared to the corresponding period in 2015. The decrease was primarily related to a $22 million decrease in employee compensation and benefits including pension costs and an $18 million decrease in scheduled outage and maintenance costs at generation facilities, partially offset by $28 million in transaction fees related to the Merger and the acquisition of PowerSecure and $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Other operations and maintenance expenses decreased slightly for year-to-date 2016 as compared to the corresponding period in 2015. The decrease was primarily due to a $45 million decrease in scheduled outage and maintenance costs at generation facilities and a $36 million decrease in employee compensation and benefits including pension costs. These decreases were partially offset by $34 million in transaction fees related to the Merger and the acquisition of PowerSecure, $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, and an increase of $10 million in general business expenses associated with Southern Power's overall growth strategy.
See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs 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
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $69 | | 13.8 | | $123 | | 12.5 |
In the second quarter 2016, depreciation and amortization was $569 million compared to $500 million for the corresponding period in 2015. The increase was primarily due to additional plant in service at the traditional electric operating companies and Southern Power.
For year-to-date 2016, depreciation and amortization was $1.1 billion compared to $987 million for the corresponding period in 2015. The increase was primarily due to an $86 million increase related to additional plant in service at the traditional electric operating companies and Southern Power. Also contributing to the increase, Gulf Power recorded $13 million less of a reduction in depreciation compared to the corresponding period in 2015, as authorized by the Florida PSC.
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – 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 Case" herein for additional information.
Estimated Loss on Kemper IGCC
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $58 | | N/M | | $102 | | N/M |
N/M - Not meaningful
In the second quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $81 million and $23 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $134 million and $32 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.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $113 | | 62.8 | | $146 | | 37.2 |
In the second quarter 2016, interest expense, net of amounts capitalized was $293 million compared to $180 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $539 million compared to $393 million in the corresponding period in 2015. These increases were primarily due to an increase in outstanding long-term debt related to the Merger, as well as increases in average outstanding long-term debt balances and higher interest rates at the traditional electric operating companies. Also contributing to the increases 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.
See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net |
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(17) | | N/M | | $(38) | | N/M |
N/M - Not meaningful
In the second quarter 2016, other income (expense), net was $(29) million compared to $(12) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(57) million compared to $(19) million for the corresponding period in 2015. These changes were primarily due to fees associated with the Bridge Agreement for the Merger. Additionally, in the second quarter 2016, revenues and costs associated with certain unregulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the second quarter and year-to-date 2016, net amounts reclassified were $7 million and $14 million, respectively.
See "Other Revenues" and "Cost of Sales" herein and Note 12 to the financial statements of Southern Company under "Southern Company – Merger Financing" in Item 8 of the Form 10-K for additional information.
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (9.9) | | $(82) | | (14.2) |
In the second quarter 2016, income taxes were $272 million compared to $302 million for the corresponding period in 2015. For year-to-date 2016, income taxes were $494 million compared to $576 million for the corresponding period in 2015. These decreases were primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by an increase related to state income tax benefits realized 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 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 business of selling electricity and, as
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
a result of closing the Merger on July 1, 2016, Southern Company Gas' primary business of natural gas distribution. These factors include the traditional electric operating companies' and Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects. Future earnings for the electricity and natural gas businesses in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of 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 business also depends on numerous factors including regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of 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 gasdemand may be affected by changes in regional and global economic conditions, which may impact future earnings.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' retail operations and wholesale 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, 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 under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement commits Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.
The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.
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.
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.
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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 Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and regional haze regulations.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published 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 have 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.
Coal Combustion Residuals
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 July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed 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 proposed Georgia EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of June 30, 2016.
Retail Regulatory Matters
Retail Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail 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 Matters – Alabama Power – Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding retail fuel cost recovery.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and
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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 Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.
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 renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.
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 by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism. Mississippi Power may retire the RECs generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.
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.
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 RECs 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.
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, and rate natural disaster reserve. 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 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.
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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 May 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 separate fuel cost recovery tariffs. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's fuel cost recovery and the NCCR tariff, respectively.
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 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 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).
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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.
The Georgia PSC approved 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. 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 2019 general base rate case.
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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 option at a future generation site in Stewart County, Georgia. The timing of cost recovery 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.
Gulf Power
Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority 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 will cover approximately 24% of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this 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 its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and 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 programs that update or expand its 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.
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 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"Retail Regulatory Matters– Georgia Power– Nuclear Construction"Construction" and "Integrated"Integrated Coal Gasification Combined Cycle"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.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital"Capital Requirements and Contractual Obligations"Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
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Integrated Coal Gasification Combined Cycle
From 2013 through June 30, 2015, Southern Company recorded pre-tax charges totaling $2.08Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.68 billion, ($1.28which includes approximately $5.43 billion after tax)of costs subject to the construction cost cap and is net of $137 million in additional DOE grants Mississippi Power received for revisions of estimated coststhe Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be incurred onused to reduce future rate impacts for customers. Mississippi Power's construction of the Kemper IGCC abovePower does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. In the aggregate, Southern Company has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. Mississippi Power's current cost estimate includes costs through October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the 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.
On February 12, 2015, the Mississippi Supreme Court issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized Mississippi Power's collection of $156 million annually to be recorded as Mirror CWIP. Among other things, the Mississippi Supreme Court reversed this order and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected. As of June 30, 2015, $331 million had been collected by Mississippi Power. The Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015.
On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
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The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations. As a result, on July 10, 2015, Mississippi Power submitted a request for interim rates 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. These interim rates are designed to collect approximately $159 million annually. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015. The ultimate outcome of these matters cannot be determined at this time.
Nuclear ConstructionLitigation
On January 29, 2015, GeorgiaApril 26, 2016, a complaint against Mississippi Power announced it was notifiedfiled in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the ContractorMississippi 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 Contractor's revised forecast for completion of Plant Vogtle Units 3Kemper IGCC and 4, which would incrementally delaythat these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the second quarter of 2019 for Unit 3 and fromKemper IGCC; ask the fourth quarter of 2018Circuit Court to the second quarter of 2020 for Unit 4).
While Georgiarevoke any licenses or certificates authorizing Mississippi Power has not agreedor Southern Company to engage in any change to the guaranteed substantial completion dates (April 2016 for Unit 3 and April 2017 for Unit 4) included in the engineering, procurement, and construction agreement relating to Plant Vogtle Units 3 and 4, Georgia Power's twelfth Vogtle Construction Monitoring (VCM) report, filed February 27, 2015, included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $5.0 billion. No Contractor costsbusiness related to the Contractor's proposed 18-month delay were includedKemper 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 June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the twelfth VCM report.state court in Gwinnett County, Georgia. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3. The Georgia PSC recognized that the certified cost does 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. Financing costs upcomplaint relates to the certified amountcancelled 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 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 be collected throughvigorously defend itself in these matters, and the NCCR tariff until the units are placed in service, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
Additionally, there are certain risks associated with the construction program in general and certain risks associated with the licensing, construction, and operation of nuclear generating units in particular, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these eventsmatters cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K for additional information.
Section 174 Research and Experimental Deduction
Southern Company reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax
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Benefits – Section 174 Research and Experimental Deduction," respectively, herein for additional information. The ultimate outcome of this tax 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
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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 or in Note 3 to the financial statements of Southern Company 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 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.
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 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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015,2016, 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 of $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, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.08 billion ($1.28 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2015.
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$540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016.
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the 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 furtherFurther cost increases and/or extensions of the expected in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality ofdifficulties integrating the systems required for sustained operations, major equipment materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, failure, unforeseen engineering or design problems start-up activities for this first-of-a-kind technology (including major equipment failure and system integration),including any repairs and/or modifications to systems, and/or operational performance (including but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through MarchOctober 31, 2016. Any further extension of the in-service date beyond October 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$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 further extension of the in-service date with respect to the Kemper IGCC beyond October 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13$14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to totalof approximately $7$3 million per month.
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"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Asset Retirement ObligationsRecently Issued Accounting Standards
AROsOn February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating 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 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 computedrequired to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as the fair value of the ultimate costs for an asset's future retirement and are recordedincome tax expense or benefit in the period in which the liability is incurred. The costs are capitalized as part of theincome statement. Southern Company currently recognizes any excess tax benefits and deficiencies related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioningexercise and vesting of the nuclear facilities - Alabama Power's Plant Farleystock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Georgia Power's ownership interests in Plants Hatch and Vogtle - and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, the Southern Company system has retirement obligations relatedintends to various landfill sites, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated withadopt the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR RuleASU in the Federal Register, setting October 19, 2015 asfourth quarter 2016. The adoption is not expected to have a material impact on the effective dateresults of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a resultoperations, financial position, or cash flows of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are basedSouthern Company.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, the traditional operating companies expect to periodically update these estimates. Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
The FASB's ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Company.
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 June 30, 2015.2016. Through June 30, 2015,2016, Southern Company has incurred non-recoverable cash expenditures of $1.62$2.28 billion and is expected to incur approximately $0.46$0.27 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC. 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"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $2.1 billion for the first six months of 2015, an increase of $37 million from2016 and the corresponding period in 2014. The increase in net cash provided from operating activities was primarily due to an increase in fuel cost recovery, partially offset by timing of accounts payable.2015. Net cash used for investing activities totaled $2.8$12.7 billion for the first six months of 20152016 primarily due to gross property additions for installation of equipmentan investment in restricted cash to comply with environmental standards,be used to complete the Merger, as well as construction of generation, transmission, and distribution facilities and acquisitionsinstallation of solar facilities.equipment to comply with environmental standards. Net cash provided from financing activities totaled $762 million$11.1 billion for the first six months of 2015. This was2016 primarily due to issuances of long-term debt partially offset byand common stock dividend paymentsassociated with financing and redemptions of long-term debt and preferred and preference stock. Fluctuations in cash flowcompleting the Merger. 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 six months of 20152016 include increases of $10.7 billion in long-term debt, $8.0 billion in restricted cash and cash equivalents, and $1.4 billion in total common stockholder's equity primarily associated with financing and completing the Merger; an increase of $2.1$2.8 billion in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, a $444 million increasefacilities; and increases of $0.7 billion in income taxes receivable, non-current associated with federal income tax benefits for deductionsAROs and $0.5 billion in other regulatory assets, deferred primarily related to R&E expenditureschanges in ash pond closure strategy primarily for the Kemper IGCC, and an increase of $406 million in accounts receivable primarily related to increases in customer billings as compared to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
December 31, 2014. Other significant changes include a $2.1 billion increase in short-term and long-term debt to fund the Southern Company subsidiaries' continuous construction programs and for other general corporate purposes, a $692 million increase in AROs primarily related to the CCR Rule, and a $619 million increase in accumulated deferred income taxes for deductions primarily related to R&E expenditures for the Kemper IGCC.Georgia Power. See Notes (A), (B), and (G)(I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company – Merger with Southern Company Gas," respectively, for additional information regarding AROs, the Kemper IGCC, and R&E expenditures, respectively.information.
At the end of the second quarter 2015,2016, the market price of Southern Company's common stock was $41.90$53.63 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.22$23.38 per share, representing a market-to-book ratio of 189%229%, compared to $49.11, $21.98,$46.79, $22.59, and 223%207%, respectively, at the end of 2014.2015. Southern Company's common stock dividend for the second quarter 20152016 was $0.5425$0.560 per share compared to $0.5250$0.5425 per share in the second quarter 2014.2015.
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 description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new 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, trust funding requirements, and unrecognized tax benefits. Approximately $3.7$3.3 billion will be required through June 30, 20162017 to fund maturities and announced redemptions of long-term debt.debt, which includes $0.6 billion with respect to Southern Company Gas that was assumed subsequent to June 30, 2016 in connection with the Merger. In addition, approximately $1.5 billion will be required for Southern Company's acquisition of a 50% equity interest in SNG, which is expected to be completed in the third quarter or early in the fourth quarter 2016. See "Sources"Sources of Capital"Capital" and Note (I) to the Condensed Financial Statements under "Southern Company – Natural Gas Pipeline Venture" herein for additional information.
The Southern Company system's construction program is currently estimated to total $9.4 billion for 2016, $5.2 billion for 2017, and $5.5 billion for 2018. These amounts include expenditures of approximately $0.7 billion related to the construction and start-up of the Kemper IGCC in 2016; $0.6 billion, $0.7 billion, and $0.4 billion to
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
continue construction on Plant Vogtle Units 3 and 4 in 2016, 2017, and 2018, respectively; and $4.4 billion, $0.9 billion, and $1.4 billion for Southern Power's acquisitions and/or construction of new generating facilities in 2016, 2017, and 2018, respectively. In addition, Southern Company Gas' construction program is currently estimated to total $0.8 billion for the period from July 1, 2016 to December 31, 2016.
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 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; 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. Additionally, planned expenditures for plant acquisitions may vary materially 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 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"Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" and "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for information regarding additional factors that may impact construction expenditures.
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 to be raisedissuances in 2015,2016, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's and Southern Company Gas' capital requirements. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Company Gas, and Southern Power 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 – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which 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 June 30, 20152016 would allow for borrowings of up to $2.2$2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $1.8$2.5 billion. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail"Retail Regulatory Matters – Georgia Power – Nuclear Construction"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 Grants is expected to be received for commercial
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
operation of the Kemper IGCC. On 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, see Note (B)3 to the Condensed Financial Statementsfinancial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" hereinin Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.
As of June 30, 2015,2016, Southern Company's current assets exceeded current liabilities by $6.6 billion. Excluding restricted cash of $8.0 billion associated with the Merger, Southern Company's current liabilities exceeded current assets by $2.1$1.3 billion, primarily due to long-term debt that is due within one year of $3.6$2.7 billion, including approximately $0.4$0.9 billion at Southern Company, $0.6the parent company, $0.2 billion at Alabama Power, $1.7$0.7 billion at Georgia Power, $0.4$0.2 billion at Gulf Power, $0.3 billion at Mississippi Power, and $0.5$0.4 billion at Southern Power. In addition, Mississippi Power has $0.5 billion in short-term bank loans scheduled to mature on April 1, 2016. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern PowerCompany Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2015,2016, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primaryan additional source of long-term borrowed funds.
The financial condition of Mississippi Power was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC. Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2015,2016, Southern Company and its subsidiaries had approximately $0.8$1.9 billion of cash and cash equivalents. In addition, Southern Company had approximately $8.0 billion of restricted cash, which was subsequently used to complete the Merger. Committed credit arrangements with banks at June 30, 20152016 were as follows:
| | | | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Due Within One Year |
Company | | 2015 | | 2016 | | 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2016 | 2017 | 2018 | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| Southern Company | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | 1,000 |
| | $ | 1,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | | 154 |
| | 124 |
| | — |
| | 1,030 |
| | 1,308 |
| | 1,307 |
| | 58 |
| | — |
| | 58 |
| | 170 |
| 3 |
| 32 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | | — |
| | 150 |
| | — |
| | 1,600 |
| | 1,750 |
| | 1,737 |
| | — |
| | — |
| | — |
| | 150 |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | | 20 |
| | 225 |
| | 30 |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 195 |
| 75 |
| 40 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
|
| Mississippi Power | | 40 |
| | 255 |
| | — |
| | — |
| | 295 |
| | 265 |
| | 30 |
| | 40 |
| | 70 |
| | 225 |
| 115 |
| 60 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
|
| Southern Power | | — |
| | — |
| | — |
| | 500 |
| | 500 |
| | 466 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| — |
| — |
| 600 |
| | 600 |
| | 560 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | 25 |
| | 45 |
| | — |
| | — |
| | 70 |
| | 70 |
| | 20 |
| | — |
| | 20 |
| | 50 |
| 25 |
| 45 |
| — |
| 40 |
| | 110 |
| | 80 |
| | 20 |
| | — |
| | 20 |
| | 50 |
|
| Total | | $ | 239 |
| | $ | 799 |
| | $ | 30 |
| | $ | 4,130 |
| | $ | 5,198 |
| | $ | 5,120 |
| | $ | 158 |
| | $ | 40 |
| | $ | 198 |
| | $ | 790 |
| $ | 218 |
| $ | 177 |
| $ | 1,665 |
| $ | 4,440 |
| | $ | 6,500 |
| | $ | 6,387 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 315 |
|
| |
| (a) | Excludes Southern Company Gas as the Merger was not completed at June 30, 2016. Southern Company Gas has committed credit arrangements with banks totaling $2.0 billion at July 1, 2016, of which $0.1 billion expire in 2017 and $1.9 billion expire in 2018. |
| |
| (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. |
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"Bank Credit Arrangements"Arrangements" herein for additional information.
A portion ofOn May 24, 2016, the unused credit with banks is allocated$8.1 billion Bridge Agreement to provide liquidity supportMerger financing, to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015extent necessary, was approximately $1.9 billion. In addition, at June 30, 2015, the traditional operating companies had $368 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.terminated.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power, 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
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Southern Company, the traditional electric operating companies, and Southern Power Company are currently 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 and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $1.9 billion. In addition, at June 30, 2016, the traditional electric operating companies had approximately $320 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Southern Company, the traditional electric operating companies, and Southern Power 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, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loansShort-term borrowings are included in notes payable in the balance sheets.
SOUTHERN COMPANY 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 June 30, 2015 | | Short-term Debt During the Period(*) | | Short-term Debt at June 30, 2016(a) | | Short-term Debt During the Period(a,b) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average 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 | | $ | 512 |
| | 0.3 | % | | $ | 1,155 |
| | 0.3 | % | | $ | 1,563 |
| | $ | 478 |
| | 0.8 | % | | $ | 1,082 |
| | 0.8 | % | | $ | 1,712 |
|
| Short-term bank debt | | 545 |
| | 1.3 | % | | 717 |
| | 1.2 | % | | 795 |
| | 125 |
| | 1.5 | % | | 215 |
| | 1.5 | % | | 262 |
|
| Total | | $ | 1,057 |
| | 0.7 | % | | $ | 1,872 |
| | 0.7 | % | | | | $ | 603 |
| | 1.0 | % | | $ | 1,297 |
| | 0.9 | % | | |
| |
(*)(a) | Excludes Southern Company Gas as the Merger was not completed at June 30, 2016. |
| |
| (b) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.2016. |
In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.
Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank notes,term loans, and operating cash flows.
Credit Rating Risk
At June 30, 2016, Southern Company and its subsidiaries dodid not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3Baa2 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate derivatives,management, and construction of new generation at Plant Vogtle Units 3 and 4.
SOUTHERN 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 June 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB and Baa2 | $ | 9 |
| |
| At BBB and/or Baa2 | | $ | 29 |
|
| At BBB- and/or Baa3 | 488 |
| $ | 597 |
|
| Below BBB- and/or Baa3 | 2,407 |
| $ | 2,519 |
|
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, anya credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which they do so.
On June 5, 2015,May 12, 2016, Fitch downgraded the senior unsecured long-term issuer defaultdebt 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+ from A-. Fitch maintained the negative ratings outlook for Mississippi PowerA- and revised the ratings outlook for Southern Company from stablenegative to negative.stable.
Subsequent to June 30, 2015, S&P placed its ratingsOn May 13, 2016, Moody's downgraded the senior unsecured long-term debt rating of Southern Company to Baa2 from Baa1 and revised the traditional operating companies on CreditWatch withratings outlook from negative implications.to stable.
Financing Activities
DuringOn 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 Merger and for other general corporate purposes.
In addition, during the first six months of 2015,2016, Southern Company issued approximately 3.211.6 million shares of common stock primarily through the employee equity compensation planplans and received proceeds of approximately $116$494 million.
The following table outlines the long-term debt financing activities for Southern Company is not currently issuing sharesand its subsidiaries for the first six months of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by independent plan administrators.2016:
|
| | | | | | | | | | | | | | | | | | | |
Company(a) | 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(b) |
| | (in millions) |
| Southern Company | $ | 8,500 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 400 |
| | 200 |
| | — |
| | 45 |
| | — |
|
| Georgia Power | 650 |
| | 500 |
| | 4 |
| | 300 |
| | 3 |
|
| Gulf Power | — |
| | 125 |
| | — |
| | — |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | 1,100 |
| | 651 |
|
| Southern Power | 1,241 |
| | — |
| | — |
| | 2 |
| | 4 |
|
| Other | — |
| | — |
| | — |
| | — |
| | 10 |
|
Elimination(c) | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) |
| Total | $ | 10,791 |
| | $ | 825 |
| | $ | 4 |
| | $ | 1,247 |
| | $ | 443 |
|
| |
| (a) | Excludes Southern Company Gas as the Merger was not completed at June 30, 2016. |
| |
| (b) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (c) | 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
On March 2, 2015,In February 2016, Southern Company announced a programentered into $700 million notional amount of forward-starting interest rate swaps to repurchase uphedge exposure to 20 million shares ofinterest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.
In May 2016, Southern Company common stockissued the following series of senior notes for an aggregate principal amount 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.
The net proceeds were used to offset all orfund a portion of the incremental shares issued under its employeeMerger and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | |
Company(a) | Senior Note Issuances | | Senior Note Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds(b) | | Revenue Bond Maturities and Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(c) |
| | (in millions) |
| Southern Company | $ | 600 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 975 |
| | 250 |
| | 80 |
| | 134 |
| | — |
| | — |
|
| Georgia Power | — |
| | 125 |
| | 170 |
| | 65 |
| | 600 |
| | 5 |
|
| Mississippi Power | — |
| | — |
| | — |
| | — |
| | — |
| | 351 |
|
| Southern Power | 650 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | 9 |
|
| Total | $ | 2,225 |
| | $ | 375 |
| | $ | 250 |
| | $ | 199 |
| | $ | 600 |
| | $ | 365 |
|
| |
(a) | Gulf Power did not issue or redeem any long-term debt during the first six months of 2015. |
| |
(b) | Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by Alabama Power since April 2015 and reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2013 and April 2015, respectively. |
| |
(c) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtednessrelated transaction costs and for other general corporate purposes.
Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuanceissuances 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.
Alabama Power's "Senior Note Issuances" reflected in the table above includes issuances in April 2015On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of $175 million additionalfinancial institutions for an aggregate principal amount of its Series 2015A 3.750% Senior Notes due$1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2045 (Additional Series 2015A Senior Notes)2018 and $250bears interest based on one-month LIBOR.
In May 2016, 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 of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion ofand the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accruedrepay existing indebtedness and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accruedfor working capital and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used forother general corporate purposes, including Alabama Power's continuous construction program.purposes.
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings under the FFB Credit Facility in an aggregate principal amount of $600$300 million in June 2015.2016. The interest rate applicable to the $600$300 million principal amount is 3.283%2.571% for an interest period that extends to 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. Georgia Power settled $350
During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million ofpursuant to the Project Credit Facilities at a weighted average interest rate swaps relatedof 2.00%. Subsequent to this borrowing for approximately $6June 30, 2016, Southern Power's subsidiaries borrowed $48 million which will be amortizedpursuant to the Project Credit Facilities at a weighted average interest expense over 10 years.rate of 1.98%.
In March 2015, GeorgiaJune 2016, Southern Power entered into a $250issued €600 million aggregate principal amount three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capitalof Series 2016A 1.00% Senior Notes due June 20, 2022 and other general corporate purposes and the loan was repaid at maturity.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an€500 million aggregate principal amount of $475 million, bearing interest based on one-month LIBOR.Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds of these loanswill be allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015effectively converted to April 1, 2016.
In June 2015, Gulf Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $40 million aggregate principal amount and the proceeds were used for credit support, working capital, and other general corporate purposes.
In addition to the amounts reflected in the table above, Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connectionfixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month floating rate promissory note to Southern Company in an aggregateinterest and principal amount of approximately $301 million bearing interest based on one-month LIBOR.payments. See Note (B)(H) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA""Foreign Currency Derivatives" herein for additional information.
Subsequent to June 30, 2015, Southern Power Company repaid at maturity $525 million aggregate principal amount
Also subsequent to June 30, 2015, $97.925 million aggregate principal amount of the Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
Also subsequent to June 30, 2015, Gulf Power announced the redemption in September 2015 of $60 million aggregate principal amount of its Series L 5.65% Senior Notes due September 1, 2035.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, 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.
During the six months ended June 30, 2015,2016, there were no material changes to each registrant's disclosures about market risk. 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 Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.
Item 4. Controls and Procedures.
| |
| (a) | Evaluation of disclosure controls and procedures. |
As of the end of the period covered by this quarterly report,Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company 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)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.controls over financial reporting. |
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company's 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)1934, as amended) during the second quarter 20152016 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, or Southern Power Company's 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 will be 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 June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,326 |
| | $ | 1,249 |
| | $ | 2,594 |
| | $ | 2,546 |
| $ | 1,316 |
| | $ | 1,326 |
| | $ | 2,510 |
| | $ | 2,594 |
|
| Wholesale revenues, non-affiliates | 57 |
| | 65 |
| | 123 |
| | 150 |
| 67 |
| | 57 |
| | 130 |
| | 123 |
|
| Wholesale revenues, affiliates | 20 |
| | 68 |
| | 35 |
| | 137 |
| 9 |
| | 20 |
| | 31 |
| | 35 |
|
| Other revenues | 52 |
| | 55 |
| | 104 |
| | 112 |
| 52 |
| | 52 |
| | 105 |
| | 104 |
|
| Total operating revenues | 1,455 |
| | 1,437 |
| | 2,856 |
| | 2,945 |
| 1,444 |
| | 1,455 |
| | 2,776 |
| | 2,856 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 343 |
| | 414 |
| | 653 |
| | 846 |
| 295 |
| | 343 |
| | 564 |
| | 653 |
|
| Purchased power, non-affiliates | 45 |
| | 39 |
| | 86 |
| | 96 |
| 40 |
| | 45 |
| | 76 |
| | 86 |
|
| Purchased power, affiliates | 49 |
| | 37 |
| | 103 |
| | 86 |
| 55 |
| | 49 |
| | 88 |
| | 103 |
|
| Other operations and maintenance | 370 |
| | 330 |
| | 768 |
| | 655 |
| 355 |
| | 370 |
| | 747 |
| | 768 |
|
| Depreciation and amortization | 160 |
| | 172 |
| | 318 |
| | 347 |
| 175 |
| | 160 |
| | 347 |
| | 318 |
|
| Taxes other than income taxes | 90 |
| | 88 |
| | 184 |
| | 177 |
| 94 |
| | 90 |
| | 191 |
| | 184 |
|
| Total operating expenses | 1,057 |
| | 1,080 |
| | 2,112 |
| | 2,207 |
| 1,014 |
| | 1,057 |
| | 2,013 |
| | 2,112 |
|
| Operating Income | 398 |
| | 357 |
| | 744 |
| | 738 |
| 430 |
| | 398 |
| | 763 |
| | 744 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 14 |
| | 11 |
| | 29 |
| | 21 |
| 6 |
| | 14 |
| | 16 |
| | 29 |
|
| Interest expense, net of amounts capitalized | (69 | ) | | (63 | ) | | (134 | ) | | (125 | ) | (74 | ) | | (69 | ) | | (147 | ) | | (134 | ) |
| Other income (expense), net | (14 | ) | | (3 | ) | | (18 | ) | | (8 | ) | (4 | ) | | (14 | ) | | (11 | ) | | (18 | ) |
| Total other income and (expense) | (69 | ) | | (55 | ) | | (123 | ) | | (112 | ) | (72 | ) | | (69 | ) | | (142 | ) | | (123 | ) |
| Earnings Before Income Taxes | 329 |
| | 302 |
| | 621 |
| | 626 |
| 358 |
| | 329 |
| | 621 |
| | 621 |
|
| Income taxes | 122 |
| | 119 |
| | 235 |
| | 246 |
| 142 |
| | 122 |
| | 245 |
| | 235 |
|
| Net Income | 207 |
| | 183 |
| | 386 |
| | 380 |
| 216 |
| | 207 |
| | 376 |
| | 386 |
|
| Dividends on Preferred and Preference Stock | 7 |
| | 10 |
| | 17 |
| | 20 |
| 5 |
| | 7 |
| | 9 |
| | 17 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 200 |
| | $ | 173 |
| | $ | 369 |
| | $ | 360 |
| $ | 211 |
| | $ | 200 |
| | $ | 367 |
| | $ | 369 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 207 |
| | $ | 183 |
| | $ | 386 |
| | $ | 380 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $3, $-, $- and $-, respectively | 5 |
| | — |
| | 1 |
| | — |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $-, respectively | — |
| | — |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 5 |
| | — |
| | 2 |
| | 1 |
|
| Comprehensive Income | $ | 212 |
| | $ | 183 |
| | $ | 388 |
| | $ | 381 |
|
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 Six Months
Ended June 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 386 |
| | $ | 380 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 387 |
| | 416 |
|
| Deferred income taxes | 60 |
| | 49 |
|
| Allowance for equity funds used during construction | (29 | ) | | (21 | ) |
| Other, net | (23 | ) | | (40 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (115 | ) | | (120 | ) |
| -Fossil fuel stock | 19 |
| | 94 |
|
| -Materials and supplies | 3 |
| | (2 | ) |
| -Other current assets | (55 | ) | | (57 | ) |
| -Accounts payable | (212 | ) | | (94 | ) |
| -Accrued taxes | 177 |
| | 104 |
|
| -Accrued compensation | (66 | ) | | (17 | ) |
| -Retail fuel cost over recovery | 25 |
| | (23 | ) |
| -Other current liabilities | 40 |
| | 5 |
|
| Net cash provided from operating activities | 597 |
| | 674 |
|
| Investing Activities: | | | |
| Property additions | (612 | ) | | (637 | ) |
| Nuclear decommissioning trust fund purchases | (278 | ) | | (121 | ) |
| Nuclear decommissioning trust fund sales | 278 |
| | 121 |
|
| Cost of removal, net of salvage | (28 | ) | | (30 | ) |
| Change in construction payables | 28 |
| | 71 |
|
| Other investing activities | (14 | ) | | (13 | ) |
| Net cash used for investing activities | (626 | ) | | (609 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | — |
| | 27 |
|
| Proceeds — | | | |
| Senior notes issuances | 975 |
| | — |
|
| Capital contributions from parent company | 10 |
| | 12 |
|
| Pollution control revenue bonds | 80 |
| | — |
|
| Redemptions and repurchases — | | | |
| Preferred and preference stock | (412 | ) | | — |
|
| Pollution control revenue bonds | (134 | ) | | — |
|
| Senior notes | (250 | ) | | — |
|
| Payment of preferred and preference stock dividends | (22 | ) | | (20 | ) |
| Payment of common stock dividends | (286 | ) | | (275 | ) |
| Other financing activities | (10 | ) | | 1 |
|
| Net cash used for financing activities | (49 | ) | | (255 | ) |
| Net Change in Cash and Cash Equivalents | (78 | ) | | (190 | ) |
| Cash and Cash Equivalents at Beginning of Period | 273 |
| | 295 |
|
| Cash and Cash Equivalents at End of Period | $ | 195 |
| | $ | 105 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $10 and $8 capitalized for 2015 and 2014, respectively) | $ | 118 |
| | $ | 114 |
|
| Income taxes, net | 47 |
| | 141 |
|
| Noncash transactions — Accrued property additions at end of period | 35 |
| | 89 |
|
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 June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 195 |
| | $ | 273 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 393 |
| | 345 |
|
| Unbilled revenues | | 170 |
| | 138 |
|
| Under recovered regulatory clause revenues | | 28 |
| | 74 |
|
| Other accounts and notes receivable | | 31 |
| | 23 |
|
| Affiliated companies | | 41 |
| | 37 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (9 | ) |
| Fossil fuel stock, at average cost | | 249 |
| | 268 |
|
| Materials and supplies, at average cost | | 415 |
| | 406 |
|
| Vacation pay | | 65 |
| | 65 |
|
| Prepaid expenses | | 168 |
| | 244 |
|
| Other regulatory assets, current | | 115 |
| | 84 |
|
| Other current assets | | 10 |
| | 5 |
|
| Total current assets | | 1,871 |
| | 1,953 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 23,812 |
| | 23,080 |
|
| Less accumulated provision for depreciation | | 8,565 |
| | 8,522 |
|
| Plant in service, net of depreciation | | 15,247 |
| | 14,558 |
|
| Nuclear fuel, at amortized cost | | 338 |
| | 348 |
|
| Construction work in progress | | 1,017 |
| | 1,006 |
|
| Total property, plant, and equipment | | 16,602 |
| | 15,912 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 68 |
| | 66 |
|
| Nuclear decommissioning trusts, at fair value | | 758 |
| | 756 |
|
| Miscellaneous property and investments | | 88 |
| | 84 |
|
| Total other property and investments | | 914 |
| | 906 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 526 |
| | 525 |
|
| Deferred under recovered regulatory clause revenues | | 97 |
| | 31 |
|
| Other regulatory assets, deferred | | 1,054 |
| | 1,063 |
|
| Other deferred charges and assets | | 156 |
| | 162 |
|
| Total deferred charges and other assets | | 1,833 |
| | 1,781 |
|
| Total Assets | | $ | 21,220 |
| | $ | 20,552 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 216 |
| | $ | 207 |
| | $ | 376 |
| | $ | 386 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $3, $(1), and $-, respectively | — |
| | 5 |
| | (2 | ) | | 1 |
|
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively | 1 |
| | — |
| | 2 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 5 |
| | — |
| | 2 |
|
| Comprehensive Income | $ | 217 |
| | $ | 212 |
| | $ | 376 |
| | $ | 388 |
|
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
ALABAMA POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 600 |
| | $ | 454 |
|
| Accounts payable — | | | | |
| Affiliated | | 244 |
| | 248 |
|
| Other | | 267 |
| | 443 |
|
| Customer deposits | | 88 |
| | 87 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 3 |
| | 2 |
|
| Other accrued taxes | | 88 |
| | 37 |
|
| Accrued interest | | 75 |
| | 66 |
|
| Accrued vacation pay | | 54 |
| | 54 |
|
| Accrued compensation | | 66 |
| | 131 |
|
| Other current liabilities | | 105 |
| | 82 |
|
| Total current liabilities | | 1,590 |
| | 1,604 |
|
| Long-term Debt | | 6,699 |
| | 6,176 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 3,937 |
| | 3,874 |
|
| Deferred credits related to income taxes | | 71 |
| | 72 |
|
| Accumulated deferred investment tax credits | | 121 |
| | 125 |
|
| Employee benefit obligations | | 308 |
| | 326 |
|
| Asset retirement obligations | | 1,252 |
| | 829 |
|
| Other cost of removal obligations | | 742 |
| | 744 |
|
| Other regulatory liabilities, deferred | | 219 |
| | 239 |
|
| Deferred over recovered regulatory clause revenues | | 72 |
| | 47 |
|
| Other deferred credits and liabilities | | 79 |
| | 79 |
|
| Total deferred credits and other liabilities | | 6,801 |
| | 6,335 |
|
| Total Liabilities | | 15,090 |
| | 14,115 |
|
| Redeemable Preferred Stock | | 85 |
| | 342 |
|
| Preference Stock | | 196 |
| | 343 |
|
| 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 | | 2,324 |
| | 2,304 |
|
| Retained earnings | | 2,331 |
| | 2,255 |
|
| Accumulated other comprehensive loss | | (28 | ) | | (29 | ) |
| Total common stockholder's equity | | 5,849 |
| | 5,752 |
|
| Total Liabilities and Stockholder's Equity | | $ | 21,220 |
| | $ | 20,552 |
|
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 376 |
| | $ | 386 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 419 |
| | 387 |
|
| Deferred income taxes | 175 |
| | 60 |
|
| Allowance for equity funds used during construction | (16 | ) | | (29 | ) |
| Other, net | (37 | ) | | (23 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 64 |
| | (115 | ) |
| -Fossil fuel stock | (32 | ) | | 19 |
|
| -Other current assets | (67 | ) | | (52 | ) |
| -Accounts payable | (75 | ) | | (212 | ) |
| -Accrued taxes | 98 |
| | 177 |
|
| -Accrued compensation | (50 | ) | | (66 | ) |
| -Retail fuel cost over recovery | (60 | ) | | 25 |
|
| -Other current liabilities | 8 |
| | 40 |
|
| Net cash provided from operating activities | 803 |
| | 597 |
|
| Investing Activities: | | | |
| Property additions | (645 | ) | | (612 | ) |
| Nuclear decommissioning trust fund purchases | (200 | ) | | (278 | ) |
| Nuclear decommissioning trust fund sales | 200 |
| | 278 |
|
| Cost of removal, net of salvage | (51 | ) | | (28 | ) |
| Change in construction payables | (27 | ) | | 28 |
|
| Other investing activities | (18 | ) | | (14 | ) |
| Net cash used for investing activities | (741 | ) | | (626 | ) |
| Financing Activities: | | | |
| Proceeds — | | | |
| Senior notes issuances | 400 |
| | 975 |
|
| Capital contributions from parent company | 237 |
| | 10 |
|
| Pollution control revenue bonds | — |
| | 80 |
|
| Other long-term debt issuances | 45 |
| | — |
|
| Redemptions and repurchases — |
|
| |
|
| Preferred and preference stock | — |
| | (412 | ) |
| Pollution control revenue bonds | — |
| | (134 | ) |
| Senior notes | (200 | ) | | (250 | ) |
| Payment of common stock dividends | (382 | ) | | (286 | ) |
| Other financing activities | (13 | ) | | (32 | ) |
| Net cash provided from (used for) financing activities | 87 |
| | (49 | ) |
| Net Change in Cash and Cash Equivalents | 149 |
| | (78 | ) |
| Cash and Cash Equivalents at Beginning of Period | 194 |
| | 273 |
|
| Cash and Cash Equivalents at End of Period | $ | 343 |
| | $ | 195 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $7 and $10 capitalized for 2016 and 2015, respectively) | $ | 131 |
| | $ | 118 |
|
| Income taxes, net | (122 | ) | | 47 |
|
| Noncash transactions — Accrued property additions at end of period | 94 |
| | 35 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 343 |
| | $ | 194 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 357 |
| | 332 |
|
| Unbilled revenues | | 174 |
| | 119 |
|
| Under recovered regulatory clause revenues | | 7 |
| | 43 |
|
| Income taxes receivable, current | | — |
| | 142 |
|
| Other accounts and notes receivable | | 35 |
| | 20 |
|
| Affiliated companies | | 32 |
| | 50 |
|
| Accumulated provision for uncollectible accounts | | (9 | ) | | (10 | ) |
| Fossil fuel stock, at average cost | | 271 |
| | 239 |
|
| Materials and supplies, at average cost | | 412 |
| | 398 |
|
| Vacation pay | | 66 |
| | 66 |
|
| Prepaid expenses | | 100 |
| | 83 |
|
| Other regulatory assets, current | | 87 |
| | 115 |
|
| Other current assets | | 10 |
| | 10 |
|
| Total current assets | | 1,885 |
| | 1,801 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 25,572 |
| | 24,750 |
|
| Less accumulated provision for depreciation | | 8,889 |
| | 8,736 |
|
| Plant in service, net of depreciation | | 16,683 |
| | 16,014 |
|
| Nuclear fuel, at amortized cost | | 368 |
| | 363 |
|
| Construction work in progress | | 423 |
| | 801 |
|
| Total property, plant, and equipment | | 17,474 |
| | 17,178 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 69 |
| | 71 |
|
| Nuclear decommissioning trusts, at fair value | | 759 |
| | 737 |
|
| Miscellaneous property and investments | | 101 |
| | 96 |
|
| Total other property and investments | | 929 |
| | 904 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 519 |
| | 522 |
|
| Deferred under recovered regulatory clause revenues | | 136 |
| | 99 |
|
| Other regulatory assets, deferred | | 1,100 |
| | 1,114 |
|
| Other deferred charges and assets | | 113 |
| | 103 |
|
| Total deferred charges and other assets | | 1,868 |
| | 1,838 |
|
| Total Assets | | $ | 22,156 |
| | $ | 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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 200 |
| | $ | 200 |
|
| Accounts payable — | | | | |
| Affiliated | | 293 |
| | 278 |
|
| Other | | 294 |
| | 410 |
|
| Customer deposits | | 88 |
| | 88 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 10 |
| | — |
|
| Other accrued taxes | | 93 |
| | 38 |
|
| Accrued interest | | 80 |
| | 73 |
|
| Accrued vacation pay | | 55 |
| | 55 |
|
| Accrued compensation | | 72 |
| | 119 |
|
| Liabilities from risk management activities | | 17 |
| | 55 |
|
| Other regulatory liabilities, current | | 81 |
| | 240 |
|
| Other current liabilities | | 41 |
| | 39 |
|
| Total current liabilities | | 1,324 |
| | 1,595 |
|
| Long-term Debt | | 6,894 |
| | 6,654 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 4,413 |
| | 4,241 |
|
| Deferred credits related to income taxes | | 68 |
| | 70 |
|
| Accumulated deferred investment tax credits | | 114 |
| | 118 |
|
| Employee benefit obligations | | 360 |
| | 388 |
|
| Asset retirement obligations | | 1,502 |
| | 1,448 |
|
| Other cost of removal obligations | | 699 |
| | 722 |
|
| Other regulatory liabilities, deferred | | 106 |
| | 136 |
|
| Deferred over recovered regulatory clause revenues | | 102 |
| | — |
|
| Other deferred credits and liabilities | | 69 |
| | 76 |
|
| Total deferred credits and other liabilities | | 7,433 |
| | 7,199 |
|
| Total Liabilities | | 15,651 |
| | 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 | | 2,589 |
| | 2,341 |
|
| Retained earnings | | 2,445 |
| | 2,461 |
|
| Accumulated other comprehensive loss | | (32 | ) | | (32 | ) |
| Total common stockholder's equity | | 6,224 |
| | 5,992 |
|
| Total Liabilities and Stockholder's Equity | | $ | 22,156 |
| | $ | 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
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within 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. 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. AppropriatelyAlabama 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 include 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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 |
| Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $27 | | 15.6 | | $9 | | 2.5 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 |
| Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
| $11 | | 5.5 | | $(2) | | (0.5) |
Alabama Power's net income after dividends on preferred and preference stock for the second quarter 20152016 was $200$211 million compared to $173$200 million for the corresponding period in 2014.2015. The increase was primarily related to an increase in ratesretail revenues under rate stabilization and equalization (Rate RSE) effective January 1, 2015, warmer weather in the second quarter 2015 compared to the corresponding period in 2014,Rate CNP Compliance and a decrease in depreciation, partially offset by an increase in non-fuel operations and maintenance expenses. These increases to income were partially offset by decreases in customer usage and AFUDC and increases in interest expense and depreciation and amortization.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 20152016 was $369$367 million compared to $360$369 million for the corresponding period in 2014.2015. The increasedecrease was primarily related to an increase under Rate RSE and a decrease in retail revenues associated with milder weather for year-to-date 2016 compared to the corresponding period in 2015, a decrease in AFUDC, and increases in interest expense, taxes other than income taxes, and depreciation and amortization. These decreases to income were partially offset by an increase in revenue under Rate CNP Compliance, a decrease in non-fuel operations and maintenance expenses.expenses, and a decrease in dividends on preferred and preference stock.
Retail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $77 | | 6.2 | | $48 | | 1.9 |
In the second quarter 2015, retail revenues were $1.33 billion compared to $1.25 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $2.59 billion compared to $2.55 billion for the corresponding period in 2014.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (0.8) | | $(84) | | (3.2) |
In the second quarter 2016, retail revenues were $1.32 billion compared to $1.33 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $2.51 billion compared to $2.59 billion for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
| | | | | Second Quarter 2015 |
| Year-to-Date 2015 | Second Quarter 2016 |
| Year-to-Date
2016 |
| | | (in millions) |
| (% change) |
| (in millions) |
| (% change) | (in millions) |
| (% change) |
| (in millions) |
| (% change) |
| Retail – prior year | | $ | 1,249 |
| | | | $ | 2,546 |
| | | $ | 1,326 |
| | | | $ | 2,594 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 56 |
| | 4.5 |
| | 103 |
| | 4.1 |
| 43 |
| | 3.2 |
| | 77 |
| | 3.0 |
|
| Sales growth | | 1 |
| | 0.1 |
| | 10 |
| | 0.4 |
| |
| Sales growth (decline) | | (9 | ) | | (0.7 | ) | | (1 | ) | | (0.1 | ) |
| Weather | | 18 |
| | 1.5 |
| | (2 | ) | | (0.1 | ) | (3 | ) | | (0.2 | ) | | (48 | ) | | (1.8 | ) |
| Fuel and other cost recovery | | 2 |
| | 0.1 |
| | (63 | ) | | (2.5 | ) | (41 | ) | | (3.1 | ) | | (112 | ) | | (4.3 | ) |
| Retail – current year | | $ | 1,326 |
| | 6.2 | % | | $ | 2,594 |
| | 1.9 | % | $ | 1,316 |
| | (0.8 | )% | | $ | 2,510 |
| | (3.2 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter 2015 and year-to-date 20152016 when compared to the corresponding periods in 20142015 primarily due to aincreased revenues under Rate RSE increase effective January 1, 2015.CNP Compliance associated with increases in the average net investments. 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 remained relatively flatdeclined in the second quarter 2015 and increased slightly year-to-date 20152016 when compared to the corresponding periods in 2014.2015. Industrial KWH energy sales slightly increased 0.2%decreased 5.5% and 4.5% for the second quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 as a result of an increasea decrease in demand resulting from changes in production levels primarily in the pipelines, stone, clay, and glass, automotive, and plastics sectors, offset by a decrease in demand in thechemicals, primary metals, and forest productspipelines 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 1.6% for the second quarter 2016 and remained relatively flat year-to-date 2016. Weather-adjusted residential and commercial KWH energy sales wereremained relatively flat for the second quarter and year-to-date 2015.2016.
Revenues resulting from changes in weather increaseddecreased in the second quarter 2015 due to warmer weather experienced in Alabama Power's service territory in the second quarter 2015 as compared to the corresponding period in 2014. For the second quarter 2015, the resulting increases were 2.6% and 1.5% for residential and commercial sales revenues, respectively.
Revenues resulting from changes in weather remained relatively flat year-to-date 2015 primarily2016 due to milder weather experienced in Alabama Power's service territory in the first quarter 2015 offset by warmer weather in the second quarter 2015 as compared to the corresponding periods in 2014.2015. For the second quarter 2016, the resulting decreases were 0.2% and 0.4% for residential and commercial sales revenue, respectively. For year-to-date 2016, the resulting decreases were 3.5% and 1.2% for residential and commercial sales revenue, respectively.
Fuel and other cost recovery revenues increaseddecreased in the second quarter 2015and year-to-date 2016 when compared to the corresponding periodperiods in 2014 primarily due to an increase in purchased power partially offset by a decrease in the average cost of fuel. Fuel and other cost recovery revenues decreased year-to-date 2015 when compared to the corresponding period in 2014 primarily due to a decrease in KWH generation and a decrease 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (12.3) | | $(27) | | (18.0) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 17.5 | | $7 | | 5.7 |
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 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
an increase or decrease in fuel costs and do not have a significant impact onaffect net income.
In the second quarter 2015,2016, wholesale revenues from sales to non-affiliates were $57$67 million compared to $65$57 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 12.0%40.6% increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 16.7% decrease in KWH sales.the price of energy as a result of lower gas prices. For year-to-date 2015,2016, wholesale revenues from sales to non-affiliates were $123$130 million compared to $150$123 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 10.3% decrease21.1% increase in KWH sales and an 8.7%as a result of a new wholesale contract effective December 2015, partially offset by a 12.6% decrease in the price of energy.
In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher naturalenergy as a result of lower gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates..
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(48) | | (70.6) | | $(102) | | (74.5) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (55.0) | | $(4) | | (11.4) |
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 and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clauses.
In the second quarter 2015,2016, wholesale revenues from sales to affiliates were $20$9 million compared to $68$20 million for the corresponding period in 2014.2015. The decrease was primarily duerelated to a 57.4%44.4% decrease in KWH sales and a 31.1%19.2% decrease in the price of energy. For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $137 million for the corresponding period in 2014. The decrease was primarilyenergy due to a 63.0% decrease in KWH sales and a 31.4% decreasethe availability of lower cost generation in the price of energy.
In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due to higher natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resultedSouthern Company system in lower sales of Alabama Power's generation to affiliates.2016.
Fuel and Purchased Power Expenses
| | | | | Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (71 | ) | | (17.1) | | $ | (193 | ) | | (22.8 | ) | | $ | (48 | ) | | (14.0) | | $ | (89 | ) | | (13.6 | ) |
| Purchased power – non-affiliates | | 6 |
| | 15.4 | | (10 | ) | | (10.4 | ) | | (5 | ) | | (11.1) | | (10 | ) | | (11.6 | ) |
| Purchased power – affiliates | | 12 |
| | 32.4 | | 17 |
| | 19.8 |
| | 6 |
| | 12.2 | | (15 | ) | | (14.6 | ) |
| Total fuel and purchased power expenses | | $ | (53 | ) | | $ | (186 | ) | | | | $ | (47 | ) | | $ | (114 | ) | | |
In the second quarter 2015,2016, total fuel and purchased power expenses were $437$390 million compared to $490$437 million for the corresponding period in 2014.2015. The decrease was primarily due to a $52$38 million decrease inrelated to the average cost of fuel,purchased power and a $20 million decrease related to the average cost of fuel. These decreases were partially offset by an $18$11 million decreasenet increase related to the volume of KWHs generated and a $7 million decrease in the average cost of purchased power, partially offset by a $24 million increase in the volume of KWHs purchased.
For year-to-date 2015, fuel and purchased power expenses were $842 million compared to $1.03 billion for the corresponding period in 2014. The decrease was primarily due to a $120 million decrease in the average cost of fuel, a $72 million decrease related to the volume of KWHs generated, and a $44 million decrease in the average cost of purchased power, partially offset by a $50 million increase in the volume of KWHs purchased.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2016, fuel and purchased power expenses were $728 million compared to $842 million for the corresponding period in 2015. The decrease was primarily due to a $51 million net decrease related to the volume of KWHs generated and purchased, a $39 million decrease related to the average cost of fuel, and a $24 million decrease related to the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through 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.
Details of Alabama Power's generation and purchased power were as follows:
| | | | | Second Quarter 2015 | | Second Quarter
2014 | | Year-to-Date 2015 |
| Year-to-Date 2014 | Second Quarter 2016 | | Second Quarter 2015 | | Year-to-Date 2016 |
| Year-to-Date 2015 |
Total generation (billions of KWHs) | | 15 | | 16 | | 29 | | 33 | 13 | | 15 | | 28 | | 29 |
Total purchased power (billions of KWHs) | | 2 | | 1 | | 4 | | 3 | 3 | | 2 | | 4 | | 4 |
Sources of generation (percent) — | | |
| Coal | | 59 | | 53 | | 53 | | 53 | 53 | | 59 | | 46 | | 53 |
| Nuclear | | 20 | | 24 | | 23 | | 23 | 23 | | 20 | | 25 | | 23 |
| Gas | | 15 | | 16 | | 17 | | 16 | 20 | | 15 | | 19 | | 17 |
| Hydro | | 6 | | 7 | | 7 | | 8 | 4 | | 6 | | 10 | | 7 |
Cost of fuel, generated (cents per net KWH) — | | |
| Coal | | 2.89 | | 3.30 | | 2.89 | | 3.35 | 2.84 | | 2.89 | | 2.85 | | 2.89 |
| Nuclear | | 0.82 | | 0.85 | | 0.81 | | 0.86 | 0.79 | | 0.82 | | 0.78 | | 0.81 |
| Gas | | 3.10 | | 3.80 | | 3.06 | | 3.99 | 2.52 | | 3.10 | | 2.49 | | 3.06 |
Average cost of fuel, generated (cents per net KWH)(a) | | 2.50 | | 2.76 | | 2.41 | | 2.83 | 2.28 | | 2.50 | | 2.20 | | 2.41 |
Average cost of purchased power (cents per net KWH)(b) | | 5.48 | | 5.88 | | 5.00 | | 6.18 | 3.94 | | 5.48 | | 4.37 | | 5.00 |
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(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
In the second quarter 2015,2016, fuel expense was $343$295 million compared to $414$343 million for the corresponding period in 2014.2015. The decrease was primarily due to a 17.7% decrease in the volume of KWHs generated by coal and an 18.4%18.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 14.6% decrease19.9% increase in the volume of KWHs generated by natural gas, and a 12.3% decrease in the average cost of coal per KWH generated. The decrease was partially offset by a 21.4% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall.gas.
For year-to-date 2015,2016, fuel expense was $653$564 million compared to $846$653 million for the corresponding period in 2014.2015. The decrease was primarily due to a 23.3%an 18.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 13.7% decrease in the average cost of coal per KWH generated, and a 9.6%16.5% decrease in the volume of KWHs generated by coal. The decrease wascoal, partially offset by a 22.1% decrease12.7% increase in the volume of KWHs generated by hydro facilities as a result of less rainfall.natural gas.
Purchased Power – Non-Affiliates
In the second quarter 2015,For year-to-date 2016, purchased power expense from non-affiliates was $45$76 million compared to $39$86 million for the corresponding period in 2014.2015. The increasedecrease was primarily related to a 20.7% increase4.4% decrease in the average cost of purchased power per KWH due to lower natural gas prices and a 4.4% decrease in the amount of energy purchased due to the availability of lower cost generation resulting from lower natural gas prices, decreased availability of hydro generation as a result of less rainfall, and increased customer demand due to warmer weather in the second quarter 2015 as compared to the corresponding period during 2014. The increase was partially offset by a 5.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices.purchased.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015, purchased power expense from non-affiliates was $86 million compared to $96 million for the corresponding period in 2014. The decrease was related to a 21.9% decrease in the average cost per KWH purchased as a result of lower natural gas prices partially offset by a 13.6% increase in the amount of energy purchased due to the availability of lower cost generation as a result of lower natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2015,For year-to-date 2016, purchased power expense from affiliates was $49$88 million compared to $37$103 million for the corresponding period in 2014.2015. The increasedecrease was primarily related to an 18.1% decrease in the average cost of purchased power per KWH as a 45.2%result of lower natural gas prices. The decrease was partially offset by a 4.7% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a 7.0% decrease in the average cost per KWH purchased due to lower natural gas prices.
For year-to-date 2015, purchased power expense from affiliates was $103 million compared to $86 million for the corresponding periodSouthern Company system in 2014. The increase was related to a 39.5% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. The increase was partially offset by a 14.2% decrease in the average cost per KWH purchased due to lower natural gas prices.2016.
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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $40 | | 12.1 | | $113 | | 17.3 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(15) | | (4.1) | | $(21) | | (2.7) |
In the second quarter 2015,2016, other operations and maintenance expenses were $370$355 million compared to $330$370 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to the implementationdecreases of an accounting order$10 million in 2014 allowing the deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million of non-nuclear outage expenditures in the second quarter 2014. In addition, employee benefitsbenefit costs including pension costs increased $11and $6 million and steam generation costs increasedin distribution overhead line maintenance expenses. These decreases were partially offset by an increase of $5 million primarily due to non-outagein scheduled steam and maintenanceother power generation outage costs.
For year-to-date 2015,2016, other operations and maintenance expenses were $768$747 million compared to $655$768 million for the corresponding period in 2014. Alabama Power deferred approximately $41 million of non-nuclear outage expenditures in the first half of 2014. In addition, steam generation costs increased $28 million2015. The decrease was primarily due to decreases of $19 million in employee benefit costs including pension costs, $10 million in scheduled steam and other power generation outage costs, and employee benefits including pension costs increased $21 million.$6 million in distribution overhead line maintenance expenses. These decreases were partially offset by an $8 million increase in nuclear generation outage amortization.
See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order" in Item 8 of the Form 10-K for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 9.4 | | $29 | | 9.1 |
In the second quarter 2016, depreciation and amortization was $175 million compared to $160 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $347 million compared to $318 million for the corresponding period in 2015. These increases were primarily the result of an increase in depreciation of compliance related steam equipment. 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.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Depreciation and AmortizationTaxes Other Than Income Taxes
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(12) | | (7.0) | | $(29) | | (8.4) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 4.4 | | $7 | | 3.8 |
In the second quarter 2015, depreciation and amortization was $160For year-to-date 2016, taxes other than income taxes were $191 million compared to $172$184 million for the corresponding period in 2014. For year-to-date 2015, depreciation and amortization2015. The increase was $318 million compared to $347 million for the corresponding period in 2014. These decreases were primarily due to a decrease in depreciation rates related to environmental, steam generation, transmission, and distribution assets effective January 1, 2015, as authorized by the FERC, partially offset by increases in plantstate and municipal utility license tax bases, increases in service.ad valorem taxes primarily due to an increase in assessed value of property, and an increase in payroll taxes.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 27.3 | | $8 | | 38.1 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (57.1) | | $(13) | | (44.8) |
In the second quarter 2015,2016, AFUDC equity was $14$6 million compared to $11$14 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, AFUDC equity was $29$16 million compared to $21$29 million for the corresponding period in 2014.2015. These increasesdecreases were primarily due to additionalassociated with capital expendituresprojects being placed in service for environmental and steam power environmental projects.generation in 2016.
Interest Expense, Net of Amounts Capitalized
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| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 9.5 | | $9 | | 7.2 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 7.2 | | $13 | | 9.7 |
In the second quarter 2015,For year-to-date 2016, interest expense, net of amounts capitalized was $69$147 million compared to $63$134 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of2015. The increase was primarily due to an increase in debt issuances and a reduction in amounts capitalized, partially offset by maturities and a redemption of long-term debt. See 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), Net
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $10 | | 71.4 | | $7 | | 38.9 |
In the second quarter 2016, other income (expense), net was $134$(4) million compared to $125$(14) million for the corresponding period in 2014. These increases were primarily due to new debt issuances, which include issuances to redeem long-term debt, preferred stock, and preference stock.
Other Income (Expense), Net |
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | N/M | | $(10) | | (125.0) |
N/M - Not meaningful
In the second quarter 2015,2015. For year-to-date 2016, other income (expense), net was $(14)$(11) million compared to $(3)$(18) million for the corresponding period in 2014. For year-to-date 2015, other2015. The changes were primarily due to decreases in donations, partially offset by decreases in sales of non-utility property in 2016.
Income Taxes
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| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $20 | | 16.4 | | $10 | | 4.3 |
In the second quarter 2016, income (expense), net was $(18)taxes were $142 million compared to $(8)$122 million for the corresponding period in 2014. The changes were primarily due to increases in donations.
Income Taxes
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| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 2.5 | | $(11) | | (4.5) |
In the second quarter 2015, income taxes were $122 million compared to $119 million for the corresponding period in 2014.2015. The increase was primarily due to higher pre-tax earnings partially offset byin 2016 and state income tax credits.credits taken in 2015.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015,2016, income taxes were $235$245 million compared to $246$235 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to state income tax credits taken in 2015.
Dividends on Preferred and Preference Stock
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| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(2) | | (28.6) | | $(8) | | (47.1) |
For year-to-date 2016, dividends on preferred and preference stock were $9 million compared to $17 million for the second quartercorresponding period in 2015. These decreases were primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements of Alabama Power under "Redeemable Preferred and Preference Stock" in Item 8 of the Form 10-K for additional information.
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 selling electricity. These factors include Alabama 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. Future earnings in the near term will depend, in part, upon maintaining and growing sales 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 electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. ChangesDemand 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, may impact sales for Alabama Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth andwhich may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A 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 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.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 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.
New Source Review Actions
See Note 3 to the financial statements of Alabama Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –Environmental Statutes and Regulations" andRegulations – "Retail Regulatory Matters – Environmental Accounting Order"Air Quality" of Alabama Power in Item 7 of the Form 10-K and "Retail Regulatory Matters – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutesthe EPA's final MATS rule and regional haze regulations.
On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutescompliance requirements, costs, or deadlines, and Regulations – Air Quality" ofall Alabama Power in Item 7 ofunits that are subject to the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule andhave completed the Cross State Air Pollution Rule (CSAPR).measures necessary to achieve compliance with the MATS rule by the applicable deadlines.
On June 12, 2015,Also on April 25, 2016, the EPA published a final rule requiring affected states (including Alabama)issued proposed revisions to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016.the regional haze regulations. The ultimate impact of the final ruleproposed revisions will depend on the outcome oftheir ultimate adoption, implementation, and any legal challenges and the development and approval of SIPs by the affected states 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 June 29, 2015,April 21, 2016, the U.S. Supreme CourtFERC 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, the Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case topetition for review at the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
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 EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Alabama Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Alabama Power recorded incremental asset retirement obligations (ARO) of approximately $401 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's AROs.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Alabama Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the final rules on Alabama Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
Alabama Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Alabama Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Alabama Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Alabama Power) 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 operating companies (including Alabama Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC.Circuit. The ultimate outcome of this matter cannot be determined at this time.
See REGULATION – "Federal Power Act" of Alabama Power in Item 1 of the Form 10-K for additional information regarding Alabama Power's Warrior River Project license.
On January 30, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order denying Smith Lake Improvement and Stakeholders Association's (SLISA) petition for en banc review of the court's dismissal of SLISA's appeal of the new Warrior River Project license. SLISA did not appeal this decision; therefore, this matter is now concluded and the FERC license is authorized as issued.
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
primarily through its Rate RSE, Rate CNP Compliance, rate energy cost recovery, and rate natural disaster reserve rate.reserve. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See NoteNotes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters"Matters," respectively, 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.
Rate CNP
See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism and the normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.
In April 2015, the Financial Accounting Standards Board (FASB) proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015,2016, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs)MWs representing Alabama Power's ownership interest) and beginbegan operating those unitsUnits 1 and 2 solely on natural gas. Subject to the final approvalgas in May 2016 and July 2016, respectively.
Renewables
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Alabama Power in Item 7 of the New Source Review stipulation, Alabama Power will also retire Plant Barry Unit 3 (225 MWs) which is currently unavailableForm 10-K for generation. See Note (B) to the Condensed Financial Statements herein for additional information regarding the New Source Review actions.renewable energy projects.
In accordance with an accounting order from the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power transferred the unrecovered plant asset balanceshas entered into agreements to purchase power from or to build renewable generation sources, including a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Alabama Power's financial statements.
Renewable Energy
On June 25, 2015, Alabama Power filed a petition with72-MW solar PPA approved by the Alabama PSC for a Renewable Generation Certificate (RGC).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 RGC would develop a process that allowsterms of the renewable agreements permit Alabama Power to builduse the energy and retire the associated RECs in service of its own renewable projects each less than 80 MWscustomers or purchase power from other renewable-generated sources up to 500 MWs. The Alabama PSC is expected to rule on this matter in August 2015. The ultimate outcome of this matter cannot be determined at this time.sell RECs, separately or bundled with energy.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofAlabama 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 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 application 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 Electric Utility Regulation, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirementBenefits, and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to the decommissioning of Alabama Power's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Alabama Power has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. Alabama Power also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Alabama Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Alabama Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.Contingent Obligations.
Recently Issued Accounting Standards
The FASB's ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Alabama Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015,February 25, 2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30):Leases Simplifying the Presentation of Debt Issuance Costs(Topic 842) (ASU 2016-02). The ASU 2016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Alabama Power is currently evaluating 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 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 benefit in the income statement. Alabama Power currently reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in other deferred chargesadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and assets on its balance sheet. UponAlabama Power intends to adopt the ASU in the fourth quarter 2016. The adoption the reclassification willis not expected to have a material impact on the results of operations, financial position, or cash flows of Alabama Power.
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 June 30, 2015.2016. 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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $597$803 million for the first six months of 2015, a decrease2016, an increase of $77$206 million as compared to the first six months of 2014.2015. The decreaseincrease in net cash provided from operating activities was primarily due to the timing of fossil fuel stock purchasesvendor payments and payments of accounts payable, partially offset by the timing oflower income tax payments and refunds associated withas a result of bonus depreciation. Net cash used for investing activities totaled $626$741 million for the first six months of 20152016 primarily due to gross property additions related to environmental, distribution, environmental, transmission, and steam generation. Net cash used forprovided from financing activities totaled $49$87 million for the first six months of 20152016 primarily due to the redemptions and repurchasesissuances of long-term debt and preferred and preference stock and payments of common stock dividends,a capital contribution from Southern Company, partially offset by issuancesa redemption of long-term debt. Fluctuations in cash flowdebt 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 six months of 20152016 include increases of $690$296 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, distribution, and steamnuclear generation, and $423$248 million in AROs associated with the CCR Rule. See Note (A)additional paid-in capital due to capital contributions from Southern Company, $240 million in long-term debt primarily due to the Condensed Financial Statements herein forissuance of additional informationsenior notes, and $172 million in accumulated deferred income taxes related to AROs.bonus depreciation. Other significant changes include decreases of $404$159 million in redeemable preferred and preference stockother regulatory liabilities, current, primarily due to redemptionsthe timing of fuel cost recovery and $142 million in income taxes receivable following the second quarter 2015.receipt of a federal income tax refund.
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
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 $600$200 million will be required through June 30, 20162017 to fund maturities of long-term debt.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – General" 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 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 required for construction and other purposes from sources similar to those used in the past. Alabama Power has primarily utilized funds frommeet its future capital needs through 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 COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power's current liabilities sometimes exceed current assets because of Alabama Power'slong-term debt due within one yearmaturities and the periodic use of short-term debt as a funding source, primarily to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs, which can fluctuate significantly due to the seasonality of the business.needs.
At June 30, 2015,2016, Alabama Power had approximately $195$343 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 20152016 were as follows:
| | | Expires | Expires | | | | | | Executable Term Loans | | Due Within One Year | Expires | | | | | | Due Within One Year |
| 2015 | | 2016 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2016 | | 2016 | | 2017 | | 2018 | | 2020 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) |
| $ | 154 |
| | $ | 124 |
| | $ | 1,030 |
| | $ | 1,308 |
| | $ | 1,307 |
| | $ | 58 |
| | $ | — |
| | $ | 58 |
| | $ | 170 |
| 3 |
| | $ | 32 |
| | $ | 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"Bank Credit Arrangements"Arrangements" herein for additional information.
A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $810 million. In addition, at June 30, 2015, Alabama Power had $200 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross defaultacceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross defaultacceleration provisions to other
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, or guarantee obligations over a specified threshold.the payment of which was then accelerated. Alabama Power is currently 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 borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $890 million. In addition, at June 30, 2016, Alabama Power had $87 million of 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 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 June 30, 2015 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial Paper | | $ | — |
| | —% | | $ | 17 |
| | 0.2% | | $ | 100 |
|
|
| | | | | | | | | | | |
| | | 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 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.2016. No short-term debt was outstanding at June 30, 2016. |
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
Alabama 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-BBB and/or Baa3Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At June 30, 2015,management, and transmission. The maximum potential collateral requirements under these contracts at a rating of BBB- and/or Baa3June 30, 2016 were immaterial. The maximum collateral requirements at a rating below BBB- and/or Baa3 were approximately $367 million. 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 | $ | 333 |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash.
Subsequent Additionally, a credit rating downgrade could impact the ability of Alabama Power to June 30, 2015, S&P placed its ratings of Southern Companyaccess capital markets, and would be likely to impact the traditional operating companies (including Alabama Power) on CreditWatch with negative implications.cost at which it does so.
Financing Activities
In March 2015,January 2016, Alabama Power issued $550$400 million aggregate principal amount of Series 2015A 3.750%2016A 4.30% Senior Notes due March 1, 2045.January 2, 2046. The proceeds were used to redeem $250repay at maturity $200 million aggregate principal amount of Alabama Power's Series DD 5.65%FF 5.20% Senior Notes due MarchJanuary 15, 20352016 and for general corporate purposes, including Alabama Power's continuous construction program.
ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015.
Also in April 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.
In June 2015, $18.7 millionMarch 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of the Industrial Development Board$45 million, one of the Citywhich bears interest at 2.38% per annum and two of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994, $6.15 million aggregate principal amount of the Industrial Development Board of the City of Gadsden, Pollution Control Revenue Bonds (Alabama Power Company Project), Series 1994, and $28.85 million aggregate principal amount of the Industrial Development Board of the Town of Parrish, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1994A were repaid at maturity.which bear interest based on three-month LIBOR.
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 June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 1,872 |
| | $ | 2,000 |
| | $ | 3,686 |
| | $ | 4,050 |
| $ | 1,907 |
| | $ | 1,872 |
| | $ | 3,624 |
| | $ | 3,686 |
|
| Wholesale revenues, non-affiliates | 50 |
| | 80 |
| | 118 |
| | 189 |
| 40 |
| | 50 |
| | 82 |
| | 118 |
|
| Wholesale revenues, affiliates | 4 |
| | 10 |
| | 12 |
| | 31 |
| 10 |
| | 4 |
| | 15 |
| | 12 |
|
| Other revenues | 90 |
| | 96 |
| | 178 |
| | 185 |
| 94 |
| | 90 |
| | 202 |
| | 178 |
|
| Total operating revenues | 2,016 |
| | 2,186 |
| | 3,994 |
| | 4,455 |
| 2,051 |
| | 2,016 |
| | 3,923 |
| | 3,994 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 503 |
| | 619 |
| | 1,029 |
| | 1,371 |
| 439 |
| | 503 |
| | 815 |
| | 1,029 |
|
| Purchased power, non-affiliates | 78 |
| | 63 |
| | 138 |
| | 142 |
| 92 |
| | 78 |
| | 175 |
| | 138 |
|
| Purchased power, affiliates | 115 |
| | 166 |
| | 263 |
| | 350 |
| 111 |
| | 115 |
| | 250 |
| | 263 |
|
| Other operations and maintenance | 467 |
| | 451 |
| | 943 |
| | 878 |
| 439 |
| | 467 |
| | 896 |
| | 943 |
|
| Depreciation and amortization | 202 |
| | 209 |
| | 418 |
| | 417 |
| 214 |
| | 202 |
| | 425 |
| | 418 |
|
| Taxes other than income taxes | 97 |
| | 106 |
| | 195 |
| | 209 |
| 100 |
| | 97 |
| | 197 |
| | 195 |
|
| Total operating expenses | 1,462 |
| | 1,614 |
| | 2,986 |
| | 3,367 |
| 1,395 |
| | 1,462 |
| | 2,758 |
| | 2,986 |
|
| Operating Income | 554 |
| | 572 |
| | 1,008 |
| | 1,088 |
| 656 |
| | 554 |
| | 1,165 |
| | 1,008 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (93 | ) | | (90 | ) | | (182 | ) | | (174 | ) | (99 | ) | | (93 | ) | | (193 | ) | | (182 | ) |
| Other income (expense), net | 1 |
| | 11 |
| | 16 |
| | 15 |
| 8 |
| | 1 |
| | 26 |
| | 16 |
|
| Total other income and (expense) | (92 | ) | | (79 | ) | | (166 | ) | | (159 | ) | (91 | ) | | (92 | ) | | (167 | ) | | (166 | ) |
| Earnings Before Income Taxes | 462 |
| | 493 |
| | 842 |
| | 929 |
| 565 |
| | 462 |
| | 998 |
| | 842 |
|
| Income taxes | 180 |
| | 177 |
| | 320 |
| | 343 |
| 213 |
| | 180 |
| | 373 |
| | 320 |
|
| Net Income | 282 |
| | 316 |
| | 522 |
| | 586 |
| 352 |
| | 282 |
| | 625 |
| | 522 |
|
| Dividends on Preferred and Preference Stock | 5 |
| | 5 |
| | 9 |
| | 9 |
| 5 |
| | 5 |
| | 9 |
| | 9 |
|
| Net Income After Dividends on Preferred and Preference Stock | $ | 277 |
| | $ | 311 |
| | $ | 513 |
| | $ | 577 |
| $ | 347 |
| | $ | 277 |
| | $ | 616 |
| | $ | 513 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 282 |
| | $ | 316 |
| | $ | 522 |
| | $ | 586 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $9, $-, $-, and $-, respectively | 14 |
| | — |
| | — |
| | — |
|
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $-, respectively | 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 15 |
| | 1 |
| | 1 |
| | 1 |
|
| Comprehensive Income | $ | 297 |
| | $ | 317 |
| | $ | 523 |
| | $ | 587 |
|
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 Six Months
Ended June 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 522 |
| | $ | 586 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 512 |
| | 503 |
|
| Deferred income taxes | (6 | ) | | 121 |
|
| Allowance for equity funds used during construction | (10 | ) | | (16 | ) |
| Retail fuel cost over recovery — long-term | — |
| | (44 | ) |
| Deferred expenses | 28 |
| | 31 |
|
| Contract amendment | (118 | ) | | — |
|
| Other, net | — |
| | (12 | ) |
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (21 | ) | | (353 | ) |
| -Fossil fuel stock | 101 |
| | 255 |
|
| -Prepaid income taxes | 86 |
| | (7 | ) |
| -Other current assets | (38 | ) | | (14 | ) |
| -Accounts payable | (110 | ) | | (140 | ) |
| -Accrued taxes | (125 | ) | | (65 | ) |
| -Accrued compensation | (61 | ) | | (15 | ) |
| -Retail fuel cost over recovery — short-term | — |
| | (14 | ) |
| -Other current liabilities | 14 |
| | 27 |
|
| Net cash provided from operating activities | 774 |
| | 843 |
|
| Investing Activities: | | | |
| Property additions | (853 | ) | | (906 | ) |
| Nuclear decommissioning trust fund purchases | (655 | ) | | (324 | ) |
| Nuclear decommissioning trust fund sales | 649 |
| | 322 |
|
| Change in construction payables, net of joint owner portion | 26 |
| | 52 |
|
| Prepaid long-term service agreements | (40 | ) | | (47 | ) |
| Other investing activities | (18 | ) | | (14 | ) |
| Net cash used for investing activities | (891 | ) | | (917 | ) |
| Financing Activities: | | | |
| Increase (decrease) in notes payable, net | 44 |
| | (359 | ) |
| Proceeds — | | | |
| Capital contributions from parent company | 23 |
| | 24 |
|
| Pollution control revenue bonds | 170 |
| | — |
|
| FFB loan | 600 |
| | 1,000 |
|
| Short-term borrowings | 250 |
| | — |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | (65 | ) | | (37 | ) |
| Senior notes | (125 | ) | | — |
|
| Short-term borrowings | (250 | ) | | — |
|
| Payment of preferred and preference stock dividends | (9 | ) | | (9 | ) |
| Payment of common stock dividends | (517 | ) | | (477 | ) |
| FFB loan issuance costs | — |
| | (49 | ) |
| Other financing activities | (4 | ) | | (3 | ) |
| Net cash provided from financing activities | 117 |
| | 90 |
|
| Net Change in Cash and Cash Equivalents | — |
| | 16 |
|
| Cash and Cash Equivalents at Beginning of Period | 24 |
| | 30 |
|
| Cash and Cash Equivalents at End of Period | $ | 24 |
| | $ | 46 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $5 and $8 capitalized for 2015 and 2014, respectively) | $ | 170 |
| | $ | 157 |
|
| Income taxes, net | 240 |
| | 145 |
|
| Noncash transactions — Accrued property additions at end of period | 171 |
| | 267 |
|
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 June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 24 |
| | $ | 24 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 778 |
| | 553 |
|
| Unbilled revenues | | 294 |
| | 201 |
|
| Joint owner accounts receivable | | 44 |
| | 121 |
|
| Other accounts and notes receivable | | 46 |
| | 61 |
|
| Affiliated companies | | 20 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (6 | ) | | (6 | ) |
| Fossil fuel stock, at average cost | | 338 |
| | 439 |
|
| Materials and supplies, at average cost | | 425 |
| | 438 |
|
| Vacation pay | | 91 |
| | 91 |
|
| Prepaid income taxes | | 225 |
| | 278 |
|
| Other regulatory assets, current | | 147 |
| | 136 |
|
| Other current assets | | 86 |
| | 74 |
|
| Total current assets | | 2,512 |
| | 2,428 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 31,363 |
| | 31,083 |
|
| Less accumulated provision for depreciation | | 10,961 |
| | 11,222 |
|
| Plant in service, net of depreciation | | 20,402 |
| | 19,861 |
|
| Other utility plant, net | | 10 |
| | 211 |
|
| Nuclear fuel, at amortized cost | | 551 |
| | 563 |
|
| Construction work in progress | | 4,171 |
| | 4,031 |
|
| Total property, plant, and equipment | | 25,134 |
| | 24,666 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 61 |
| | 58 |
|
| Nuclear decommissioning trusts, at fair value | | 814 |
| | 789 |
|
| Miscellaneous property and investments | | 37 |
| | 38 |
|
| Total other property and investments | | 912 |
| | 885 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 681 |
| | 698 |
|
| Deferred under recovered regulatory clause revenues | | — |
| | 197 |
|
| Other regulatory assets, deferred | | 2,063 |
| | 1,753 |
|
| Other deferred charges and assets | | 446 |
| | 403 |
|
| Total deferred charges and other assets | | 3,190 |
| | 3,051 |
|
| Total Assets | | $ | 31,748 |
| | $ | 31,030 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 352 |
| | $ | 282 |
| | $ | 625 |
| | $ | 522 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $-, $9, $-, and $-, respectively | — |
| | 14 |
| | — |
| | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $-, $-, $1, and $1, respectively | 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Total other comprehensive income (loss) | 1 |
| | 15 |
| | 1 |
| | 1 |
|
| Comprehensive Income | $ | 353 |
| | $ | 297 |
| | $ | 626 |
| | $ | 523 |
|
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 1,660 |
| | $ | 1,154 |
|
| Notes payable | | 200 |
| | 156 |
|
| Accounts payable — | | | | |
| Affiliated | | 392 |
| | 451 |
|
| Other | | 574 |
| | 555 |
|
| Customer deposits | | 259 |
| | 253 |
|
| Other accrued taxes | | 207 |
| | 332 |
|
| Accrued interest | | 96 |
| | 96 |
|
| Accrued vacation pay | | 62 |
| | 63 |
|
| Accrued compensation | | 81 |
| | 153 |
|
| Other current liabilities | | 309 |
| | 257 |
|
| Total current liabilities | | 3,840 |
| | 3,470 |
|
| Long-term Debt | | 8,914 |
| | 8,683 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 5,524 |
| | 5,507 |
|
| Deferred credits related to income taxes | | 103 |
| | 106 |
|
| Accumulated deferred investment tax credits | | 191 |
| | 196 |
|
| Employee benefit obligations | | 870 |
| | 903 |
|
| Asset retirement obligations | | 1,301 |
| | 1,223 |
|
| Other deferred credits and liabilities | | 286 |
| | 255 |
|
| Total deferred credits and other liabilities | | 8,275 |
| | 8,190 |
|
| Total Liabilities | | 21,029 |
| | 20,343 |
|
| 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 | | 6,232 |
| | 6,196 |
|
| Retained earnings | | 3,830 |
| | 3,835 |
|
| Accumulated other comprehensive loss | | (7 | ) | | (8 | ) |
| Total common stockholder's equity | | 10,453 |
| | 10,421 |
|
| Total Liabilities and Stockholder's Equity | | $ | 31,748 |
| | $ | 31,030 |
|
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 625 |
| | $ | 522 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 530 |
| | 512 |
|
| Deferred income taxes | 157 |
| | (6 | ) |
| Allowance for equity funds used during construction | (24 | ) | | (10 | ) |
| Deferred expenses | 39 |
| | 28 |
|
| Contract amendment | — |
| | (118 | ) |
| Settlement of asset retirement obligations | (52 | ) | | (9 | ) |
| Other, net | 6 |
| | 9 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (25 | ) | | (21 | ) |
| -Fossil fuel stock | 61 |
| | 101 |
|
| -Prepaid income taxes | (1 | ) | | 86 |
|
| -Other current assets | 11 |
| | (38 | ) |
| -Accounts payable | 6 |
| | (110 | ) |
| -Accrued taxes | (137 | ) | | (125 | ) |
| -Accrued compensation | (44 | ) | | (61 | ) |
| -Other current liabilities | 17 |
| | 14 |
|
| Net cash provided from operating activities | 1,169 |
| | 774 |
|
| Investing Activities: | | | |
| Property additions | (1,058 | ) | | (853 | ) |
| Nuclear decommissioning trust fund purchases | (386 | ) | | (655 | ) |
| Nuclear decommissioning trust fund sales | 380 |
| | 649 |
|
| Cost of removal, net of salvage | (34 | ) | | (46 | ) |
| Change in construction payables, net of joint owner portion | (75 | ) | | 26 |
|
| Prepaid long-term service agreements | (14 | ) | | (40 | ) |
| Other investing activities | 17 |
| | 28 |
|
| Net cash used for investing activities | (1,170 | ) | | (891 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 39 |
| | 44 |
|
| Proceeds — | | | |
| Capital contributions from parent company | 239 |
| | 23 |
|
| Pollution control revenue bonds | — |
| | 170 |
|
| Senior notes | 650 |
| | — |
|
| FFB loan | 300 |
| | 600 |
|
| Short-term borrowings | — |
| | 250 |
|
| Redemptions and repurchases — | | | |
| Pollution control revenue bonds | (4 | ) | | (65 | ) |
| Senior notes | (500 | ) | | (125 | ) |
| Short-term borrowings | — |
| | (250 | ) |
| Payment of common stock dividends | (653 | ) | | (517 | ) |
| Other financing activities | (16 | ) | | (13 | ) |
| Net cash provided from financing activities | 55 |
| | 117 |
|
| Net Change in Cash and Cash Equivalents | 54 |
| | — |
|
| Cash and Cash Equivalents at Beginning of Period | 67 |
| | 24 |
|
| Cash and Cash Equivalents at End of Period | $ | 121 |
| | $ | 24 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid during the period for — | | | |
| Interest (net of $10 and $5 capitalized for 2016 and 2015, respectively) | $ | 174 |
| | $ | 170 |
|
| Income taxes, net | 78 |
| | 240 |
|
| Noncash transactions — Accrued property additions at end of period | 288 |
| | 171 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 121 |
| | $ | 67 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 592 |
| | 541 |
|
| Unbilled revenues | | 293 |
| | 188 |
|
| Joint owner accounts receivable | | 51 |
| | 227 |
|
| Income taxes receivable, current | | — |
| | 114 |
|
| Other accounts and notes receivable | | 52 |
| | 57 |
|
| Affiliated | | 16 |
| | 18 |
|
| Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) |
| Fossil fuel stock, at average cost | | 340 |
| | 402 |
|
| Materials and supplies, at average cost | | 477 |
| | 449 |
|
| Vacation pay | | 93 |
| | 91 |
|
| Prepaid income taxes | | 157 |
| | 156 |
|
| Other regulatory assets, current | | 123 |
| | 123 |
|
| Other current assets | | 55 |
| | 92 |
|
| Total current assets | | 2,368 |
| | 2,523 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 33,045 |
| | 31,841 |
|
| Less accumulated provision for depreciation | | 11,087 |
| | 10,903 |
|
| Plant in service, net of depreciation | | 21,958 |
| | 20,938 |
|
| Other utility plant, net | | 174 |
| | 171 |
|
| Nuclear fuel, at amortized cost | | 566 |
| | 572 |
|
| Construction work in progress | | 4,655 |
| | 4,775 |
|
| Total property, plant, and equipment | | 27,353 |
| | 26,456 |
|
| Other Property and Investments: | | | | |
| Equity investments in unconsolidated subsidiaries | | 62 |
| | 64 |
|
| Nuclear decommissioning trusts, at fair value | | 819 |
| | 775 |
|
| Miscellaneous property and investments | | 42 |
| | 43 |
|
| Total other property and investments | | 923 |
| | 882 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 677 |
| | 679 |
|
| Other regulatory assets, deferred | | 2,524 |
| | 2,152 |
|
| Other deferred charges and assets | | 170 |
| | 173 |
|
| Total deferred charges and other assets | | 3,371 |
| | 3,004 |
|
| Total Assets | | $ | 34,015 |
| | $ | 32,865 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 658 |
| | $ | 712 |
|
| Notes payable | | 197 |
| | 158 |
|
| Accounts payable — | | | | |
| Affiliated | | 407 |
| | 411 |
|
| Other | | 541 |
| | 750 |
|
| Customer deposits | | 268 |
| | 264 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | — |
| | 12 |
|
| Other accrued taxes | | 199 |
| | 325 |
|
| Accrued interest | | 107 |
| | 99 |
|
| Accrued vacation pay | | 64 |
| | 62 |
|
| Accrued compensation | | 88 |
| | 142 |
|
| Asset retirement obligations, current | | 323 |
| | 179 |
|
| Other current liabilities | | 299 |
| | 181 |
|
| Total current liabilities | | 3,151 |
| | 3,295 |
|
| Long-term Debt | | 10,120 |
| | 9,616 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 5,788 |
| | 5,627 |
|
| Deferred credits related to income taxes | | 104 |
| | 105 |
|
| Accumulated deferred investment tax credits | | 199 |
| | 204 |
|
| Employee benefit obligations | | 901 |
| | 949 |
|
| Asset retirement obligations, deferred | | 2,249 |
| | 1,737 |
|
| Other deferred credits and liabilities | | 302 |
| | 347 |
|
| Total deferred credits and other liabilities | | 9,543 |
| | 8,969 |
|
| Total Liabilities | | 22,814 |
| | 21,880 |
|
| 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 | | 6,527 |
| | 6,275 |
|
| Retained earnings | | 4,024 |
| | 4,061 |
|
| Accumulated other comprehensive loss | | (14 | ) | | (15 | ) |
| Total common stockholder's equity | | 10,935 |
| | 10,719 |
|
| Total Liabilities and Stockholder's Equity | | $ | 34,015 |
| | $ | 32,865 |
|
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
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Georgia Power operates as a vertically integrated utility providing electricity 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. 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, and fuel. In addition, construction continues on Plant Vogtle Units 3 and 4 in which4. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. AppropriatelyGeorgia 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.
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, 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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(34) | | (10.9) | | $(64) | | (11.1) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $70 | | 25.3 | | $103 | | 20.1 |
Georgia Power's net income after dividends on preferred and preference stock was $347 million for the second quarter 2015 was $277 million2016 compared to $311$277 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, net income after dividends on preferred and preference stock was $513$616 million compared to $577$513 million for the corresponding period in 2014.2015. The decreasesincreases were primarily due to higher non-fuel operations and maintenance expenses andan 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, and lower non-fuel operating expenses. The increases were partially offset by increasesdecreases in retail base revenues effective January 1, 2015 as authorized by the Georgia PSC. Additionally, warmerdue to milder weather in the second quarter 2015for year-to-date 2016 compared to the corresponding period in 2014 contributed to increases in retail base revenues.2015.
See Note (A) to Condensed Financial Statements herein for additional information.
Retail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) |
| (% change) |
| $(128) | | (6.4) | | $(364) | | (9.0) |
In the second quarter 2015, retail revenues were $1.87 billion compared to $2.00 billion for the corresponding period in 2014. For year-to-date 2015, retail revenues were $3.69 billion compared to $4.05 billion for the corresponding period in 2014.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Revenues
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) |
| (% change) |
| $35 | | 1.9 | | $(62) | | (1.7) |
In the second quarter 2016, retail revenues were $1.91 billion compared to $1.87 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $3.62 billion compared to $3.69 billion for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
| | | | | Second Quarter
2015 | | Year-to-Date 2015 | Second Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) |
| (% change) | | (in millions) | | (% change) | (in millions) |
| (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 2,000 |
| | | | $ | 4,050 |
| | | $ | 1,872 |
| | | | $ | 3,686 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | (27 | ) | | (1.3 | ) | | 3 |
| | 0.1 |
| 101 |
| | 5.4 |
| | 146 |
| | 3.9 |
|
| Sales growth | | 21 |
| | 1.0 |
| | 37 |
| | 0.9 |
| |
| Sales growth (decline) | | (6 | ) | | (0.3 | ) | | 2 |
| | 0.1 |
|
| Weather | | 22 |
| | 1.1 |
| | 6 |
| | 0.1 |
| 2 |
| | 0.1 |
| | (31 | ) | | (0.8 | ) |
| Fuel cost recovery | | (144 | ) | | (7.2 | ) | | (410 | ) | | (10.1 | ) | (62 | ) | | (3.3 | ) | | (179 | ) | | (4.9 | ) |
| Retail – current year | | $ | 1,872 |
| | (6.4 | )% | | $ | 3,686 |
| | (9.0 | )% | $ | 1,907 |
| | 1.9 | % | | $ | 3,624 |
| | (1.7 | )% |
Revenues associated with changes in rates and pricing decreasedincreased in the second quarter 2015and year-to-date 2016 when compared to the corresponding periodperiods in 20142015 primarily due to increases in base tariffs approved under the 2013 ARP and the NCCR tariff, all effective January 1, 2016, as well as the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing, partially offset by base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, which were both effective January 1, 2015. Revenues associated with changes in rates and pricing increased slightly year-to-date 2015 when compared to the corresponding period in 2014 primarily due to the base tariff increases and increases in collections for financing costs described above, partially offset by the error correction.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 and Note (A) to the Condensed Financial Statements herein for additional information.
Revenues attributable to changes in sales increaseddecreased in the second quarter 2016 and increased slightly year-to-date 20152016 when compared to the corresponding periods in 2014.2015. Weather-adjusted residential KWH sales increased 2.6%0.6%, weather-adjusted commercial KWH sales increased 1.1%decreased 1.7%, and weather-adjusted industrial KWH sales remained flatincreased 0.6% in the second quarter 20152016 when compared to the corresponding period in 2014.2015. For year-to-date 2015,2016, weather-adjusted residential KWH sales increased 1.8%0.5%, weather-adjusted commercial KWH sales increased 1.0%decreased 0.5%, and weather-adjusted industrial KWH sales increased 2.0%1.0% when compared to the corresponding period in 2014.2015. An increase of approximately 28,00026,000 residential customers since June 30, 20142015 contributed to the increase in weather-adjusted residential KWH sales. IncreasedA decline in average customer usage andcontributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,000 commercial customers since June 30, 2014 contributed to the increase in weather-adjusted commercial sales.2015. Increased demand in the paper, stone, clay, and glass, food processing, transportation, rubber, and pipelinenon-manufacturing sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by a decreasedecreased demand in the chemicals sector.pipeline, military, and textiles sectors.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $144$62 million and $410$179 million in the second quarter and year-to-date 2015,2016, respectively, when compared to the corresponding periods in 20142015 primarily due to lower coal and natural gas coal,prices and nuclear fuel costs.lower energy sales. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail"Retail Regulatory Matters – Fuel Cost Recovery"Recovery" herein for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(30) | | (37.5) | | $(71) | | (37.6) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(10) | | (20.0) | | $(36) | | (30.5) |
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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 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 ofto produce the energy.
In the second quarter 2015,2016, wholesale revenues from sales to non-affiliates were $50$40 million compared to $80$50 million for the corresponding period in 20142015 related to an $8 million decrease in capacity revenues and a $2 million decrease in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $82 million compared to $118 million for the corresponding period in 2015 related to a $15$21 million decrease in energycapacity revenues and a $15 million decrease in capacityenergy revenues. For year-to-date 2015, wholesale revenues from sales to non-affiliates were $118 million compared to $189 million for the corresponding period in 2014 related to a $48 million decrease in energy revenues and a $23 million decrease in capacity revenues. The decreases in energy revenues were primarily due to the lower cost of natural gas and coal. The decreases in capacity revenues reflect the expiration of wholesale contracts in December 2014the second quarter 2016. In addition, the decrease in capacity revenues for year-to-date 2016 reflects the retirement of 14 coal-fired generating units after March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decreases in energy revenues were primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the retirements of Plant Branch Units 1, 3, and 4, Plant Yates Units 1 through 5, and Plant McManus Units 1 and 2.Form 10-K for additional information related to Georgia Power's environmental compliance strategy.
WholesaleOther Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(6) | | (60.0) | | $(19) | | (61.3) |
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 energy is generally sold at marginal cost. |
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $4 | | 4.4 | | $24 | | 13.5 |
In the second quarter 2015, wholesale2016, other revenues from sales to affiliates were $4$94 million compared to $10$90 million for the corresponding period in 2014.2015. The increase was primarily due to a $3 million increase in outdoor lighting revenues. For year-to-date 2015, wholesale2016, other revenues from sales to affiliates were $12$202 million compared to $31$178 million for the corresponding period in 2014.2015. The decreases wereincrease was primarily due to lower natural gasa $14 million increase related to customer temporary facilities services revenues and coal prices.a $6 million increase in outdoor lighting revenues.
Fuel and Purchased Power Expenses
| | | | | Second Quarter 2015
vs.
Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (116 | ) | | (18.7 | ) | | $ | (342 | ) | | (24.9 | ) | | $ | (64 | ) | | (12.7 | ) | | $ | (214 | ) | | (20.8 | ) |
| Purchased power – non-affiliates | | 15 |
| | 23.8 |
| | (4 | ) | | (2.8 | ) | | 14 |
| | 17.9 |
| | 37 |
| | 26.8 |
|
| Purchased power – affiliates | | (51 | ) | | (30.7 | ) | | (87 | ) | | (24.9 | ) | | (4 | ) | | (3.5 | ) | | (13 | ) | | (4.9 | ) |
| Total fuel and purchased power expenses | | $ | (152 | ) | | | | $ | (433 | ) | | | | $ | (54 | ) | | | | $ | (190 | ) | | |
In the second quarter 2015, total fuel and purchased power expenses were $696 million compared to $848 million in the corresponding period in 2014. The decrease in the second quarter 2015 was primarily due to a $154 million decrease in the average cost of fuel related to lower natural gas, coal, and nuclear fuel prices and a decrease in the average cost of purchased power due to lower natural gas prices and a $21 million decrease in the volume of KWHs generated due to less available generating capacity as a result of plant retirements in April 2015, partially offset by a $23 million increase in the volume of KWHs purchased due to lower natural gas prices.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015,In the second quarter 2016, total fuel and purchased power expenses were $1.43$642 million compared to $696 million in the corresponding period in 2015. The decrease in the second quarter 2016 was due to a decrease of $63 million in the average cost of fuel and purchased power related to lower coal and natural gas prices, partially offset by a $9 million net increase related to the volume of KWHs generated and purchased to meet customer demand.
For year-to-date 2016, total fuel and purchased power expenses were $1.24 billion compared to $1.86$1.43 billion in the corresponding period in 2014.2015. The decrease in year-to-date 20152016 was primarily due to a $396decrease of $152 million decrease in the average cost of fuel and purchased power related to lower natural gas, coal and nuclear fuel prices and a decrease in the average cost of purchased power due to lower natural gas prices and a $99$38 million net decrease inrelated to the volume of KWHs generated due to less available generating capacityand purchased, primarily as a result of plant retirementsmilder weather as compared to the corresponding period in April 2015 partially offset by a $62 million increaseresulting in the volume of KWHs purchased due to lower natural gas prices.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 FUTURE EARNINGS POTENTIAL – "Retail"Retail Regulatory Matters – Fuel Cost Recovery"Recovery" herein for additional information.
Details of Georgia Power's generation and purchased power were as follows:
| | | | | Second Quarter
2015 | | Second Quarter
2014 | | Year-to-Date 2015 |
| Year-to-Date 2014 | Second Quarter 2016 | | Second Quarter 2015 | | Year-to-Date 2016 |
| Year-to-Date 2015 |
Total generation (billions of KWHs) | | 17 | | 18 | | 34 | | 36 | 17 | | 17 | | 33 | | 34 |
Total purchased power (billions of KWHs) | | 6 | | 5 | | 11 | | 10 | 6 | | 6 | | 12 | | 11 |
Sources of generation (percent) — | | |
| Coal | | 40 | | 42 | | 37 | | 45 | 36 | | 40 | | 33 | | 37 |
| Nuclear | | 24 | | 22 | | 23 | | 21 | 24 | | 24 | | 24 | | 23 |
| Gas | | 34 | | 34 | | 38 | | 31 | 38 | | 34 | | 40 | | 38 |
| Hydro | | 2 | | 2 | | 2 | | 3 | 2 | | 2 | | 3 | | 2 |
Cost of fuel, generated (cents per net KWH) — | | |
| Coal | | 3.75 | | 4.20 | | 4.18 | | 4.65 | 3.37 | | 3.75 | | 3.45 | | 4.18 |
| Nuclear | | 0.85 | | 0.93 | | 0.71 | | 0.92 | 0.84 | | 0.85 | | 0.85 | | 0.71 |
| Gas | | 2.67 | | 3.81 | | 2.65 | | 4.09 | 2.18 | | 2.67 | | 2.10 | | 2.65 |
Average cost of fuel, generated (cents per net KWH) | | 2.66 | | 3.32 | | 2.76 | | 3.66 | 2.29 | | 2.66 | | 2.26 | | 2.76 |
Average cost of purchased power (cents per net KWH)(*) | | 4.56 | | 5.55 | | 4.47 | | 5.66 | 4.45 | | 4.56 | | 4.38 | | 4.47 |
(*) Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
| |
| (*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2015,2016, fuel expense was $503$439 million compared to $619$503 million in the corresponding period in 2014.2015. The decrease was primarily due to a 19.9%13.9% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 6.7% decrease in the volume of KWHs generated by coal.
For year-to-date 2015, fuel expense was $1.03 billion compared to $1.37 billion in the corresponding period in 2014. The decrease was primarily due to a 24.6% decrease in the average cost of fuel per KWH generated and a 22.2%10.4% decrease in the volume of KWHs generated by coal, partially offset by a 13.9%9.7% increase in the volume of KWHs generated by natural gas.
Purchased Power – Non-Affiliates
In the second quarter 2015, purchased powerFor year-to-date 2016, fuel expense from non-affiliates was $78$815 million compared to $63 million$1.03 billion in the corresponding period in 2014.2015. The increasedecrease was primarily due to an 18.1% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 94.1% increase12.7% decrease in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the second quarter 2015 compared to the corresponding period in 2014 and to replace the energy previously generated by the plants retired in April 2015,coal.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Purchased Power – Non-Affiliates
In the second quarter 2016, purchased power expense from non-affiliates was $92 million compared to $78 million in the corresponding period in 2015. The increase was primarily due to a 19.7% increase in the volume of KWHs purchased, partially offset by a 36.0%4.7% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.
For year-to-date 2015,2016, purchased power expense from non-affiliates was $138$175 million compared to $142$138 million in the corresponding period in 2014.2015. The decreaseincrease was primarily due to a 32.9%38.5% increase in the volume of KWHs purchased, partially offset by a 13.9% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices, partially offset by a 48.5% increase in volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the second quarter 2015 compared to the corresponding period in 2014 and to replace the energy previously generated by the plants retired in April 2015.prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2015,2016, purchased power expense from affiliates was $115$111 million compared to $166$115 million in the corresponding period in 2014.2015. The decrease was the result of a 3.0% decrease in the average cost per KWH purchased, partially offset by a 5.2% increase in the volume of KWHs purchased as Georgia Power's units generally dispatched at a higher cost than other Southern Company system resources. For year-to-date 2015,2016, purchased power expense from affiliates was $263$250 million compared to $350$263 million in the corresponding period in 2014.2015. The decreases were due todecrease was the result of a 17.7%1.6% decrease in the second quarter 2015 and a 20.7% decrease for year-to-date 2015 in the average cost ofper KWH purchased primarily resulting from lower natural gas prices.and a 2.8% decrease in the volume of KWHs purchased.
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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $16 | | 3.5 | | $65 | | 7.4 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(28) | | (6.0) | | $(47) | | (5.0) |
In the second quarter 2015,2016, other operations and maintenance expenses were $467$439 million compared to $451$467 million in the corresponding period in 2014.2015. The increasedecrease was primarily due to increasesdecreases of $25 million in scheduled generation outage and maintenance costs and $11 million in employee benefits including pension costs, partially offset by an increase of $10 million in transmission expenses.
For year-to-date 2016, other operations and maintenance expenses were $896 million compared to $943 million in the corresponding period in 2015. The decrease was primarily due to decreases of $42 million in generation scheduled outage and maintenance costs and $18 million in employee compensation and benefits including pension costs, $8 million in scheduled outage-related costs, and $3 million primarily related to customer incentive and demand-side management costs, partially offset by a decreasean increase of $7$14 million in transmission and distribution overhead line maintenance. expenses.
See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
For year-to-date 2015, other operationsDepreciation and maintenance expenses were $943Amortization
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $12 | | 5.9 | | $7 | | 1.7 |
In the second quarter 2016, depreciation and amortization was $214 million compared to $878$202 million in the corresponding period in 2014.2015. The increase was primarily due to increases of $31 million in employee compensation and benefits including pension costs, $15 million in scheduled outage-related costs, and $13 million primarily related to customer incentive and demand-side management costs.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (3.3) | | $1 | | 0.2 |
In the second quarter 2015, depreciation and amortization was $202 million compared to $209 million in the corresponding period in 2014. The decrease was primarily due to decreases in other cost of removal ofa $9 million and depreciation of $2 million as authorized by the Georgia PSC under the 2013 ARP, partially offset by an increase to additional plant in amortization of $4 million.service
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and a $9 million increase in other cost of removal, partially offset by a decrease of $5 million related to amortization of nuclear construction financing costs that was completed in December 2015.
For year-to-date 2015,2016, depreciation and amortization was $418$425 million compared to $417$418 million in the corresponding period in 2014.2015. The increase was primarily due to ana $16 million increase to additional plant in service and a $9 million increase in depreciation and amortizationother cost of $10 million as authorized by the Georgia PSC under the 2013 ARP,removal, partially offset by a decrease in other cost of removal of $9 million.million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $9 million related to unit retirements.
Taxes Other Than Income TaxesInterest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(9) | | (8.5) | | $(14) | | (6.7) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 6.5 | | $11 | | 6.0 |
In the second quarter 2015, taxes other than income taxes were $972016, interest expense, net of amounts capitalized was $99 million compared to $106$93 million in the corresponding period in 2014. 2015. The increase was primarily due to a $10 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.
For the year-to-date 2015, taxes other than income taxes were $1952016, interest expense, net of amounts capitalized was $193 million compared to $209$182 million in the corresponding period in 2014.2015. The decreases wereincrease was primarily due to decreasesa $16 million increase in interest due to additional long-term borrowings from the FFB, partially offset by an increase of $6 million and $11$5 million in municipal franchise fees related to lower retail revenues in the second quarter 2015 and year-to-date 2015, respectively, as well as decreases of $2 million in property taxes for each period.AFUDC debt.
Other Income (Expense), netTaxes
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(10) | | (90.9) | | $1 | | 6.6 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $33 | | 18.3 | | $53 | | 16.6 |
In the second quarter 2015, other2016, income (expense), net was $1taxes were $213 million compared to $11$180 million in the corresponding period in 2014.2015. For year-to-date 2015, other2016, income (expense), net was $16taxes were $373 million compared to $15$320 million in the corresponding period in 2014.2015. The changes primarily relate to AFUDC equity.
Income Taxes
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $3 | | 1.7 | | $(23) | | (6.7) |
For year-to-date 2015, income taxesincreases were $320 million compared to $343 million in the corresponding period in 2014. The decrease was primarily due to lowerhigher pre-tax earnings.
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. 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 the completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining and growing sales 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 electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. ChangesDemand 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, may impact sales for Georgia Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth andwhich may impact future earnings. 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.
GEORGIA POWER COMPANY
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. 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.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
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and "Retail Regulatory Matters – Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions at Georgia Power.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule and the Cross State Air Pollution Rule (CSAPR).regional haze regulations.
On April 25, 2016, in response to a June 12, 2015 U.S. Supreme Court opinion, the EPA published a finalits supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule requiring affected states (includingcompliance requirements, costs, or deadlines, and all Georgia Alabama, and Florida)Power units that are subject to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSMthe MATS rule have completed the measures necessary to achieve compliance with the MATS rule by no later than November 22, 2016.the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the final ruleproposed revisions will depend on the outcome oftheir ultimate adoption, implementation, and any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Georgia, Alabama, and Florida. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
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 EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
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 April 17, 2015,June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the EPA publishednext 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 July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final ruleRule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The proposed Georgia EPD regulations are expected to be finalized in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate2016 and are not anticipated to have a material impact of the CCR Rule cannot be determined at this timeand will depend on Georgia Power's ongoing review ofcompliance obligations under the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Georgia Power recorded incremental asset retirement obligations (ARO) of approximately $82 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates.Rule. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues"asset retirement obligations (ARO) as of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Georgia Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the final rules on Georgia Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
Georgia Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FERC regulations governing such authority, the traditional operating companies (including Georgia Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Georgia Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Georgia Power) 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 operating companies (including Georgia Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.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 (DSM) tariffs, ECCR tariffs, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below 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 fuel cost recovery and the NCCR tariff, respectively.
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.information regarding the 2013 ARP.
Renewables Development
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Georgia Power in Item 7 of the Form 10-K for information regarding renewable energy projects.
As part of the Georgia Power Advanced Solar Initiative program,(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 ten 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 were approved byowns the RECs retains the right to use them.
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).
On July 28, 2016, the Georgia PSC in 2014voted to approve the 2016 IRP including the decertification and provide forretirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the purchasedecertification of energy from 515the Intercession City unit (143 MWs of solar capacity. These PPAs are expected to commence in December 2015total capacity). On August 2, 2016, the Plant Mitchell and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power,Plant Kraft units were retired. Georgia Power expects that 249 MWs ofexercised its contractual option to sell its 33% ownership interest in the 515 MWs of contracted capacity will be purchased from solar facilities owned or under development by Southern Power.Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.
On June 15, 2015, Georgia Power executed a PPA to purchase a total of 58 MWs of biomass capacity and energy from a 79-MW facility in Georgia that will begin in 2017 and end in 2047. This PPA was approved by the Georgia PSC on April 15, 2015. Georgia Power also entered into an energy-only PPA for the remaining 21 MWs from the same facility.
On July 21, 2015,Additionally, the Georgia PSC approved Georgia Power's requestenvironmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to build, own, and operate a 46-MW solar generation facility at a U.S. Marine Corps base in Albany, Georgia by the end of 2016.
Integrated Resource Plan
To comply with the April 16, 2015 effective date of the MATS rule,existing government-imposed environmental mandates, subject to limits on expenditures for Plant Branch UnitsMcIntosh Unit 1 3, and 4 (1,266 MWs), Plant YatesHammond Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at4.
The Georgia PSC approved reclassification of the remaining net book value of Plant Mitchell Unit 3 (155 MWs) and its decertificationcosts 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. 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 requesteddeferred for consideration in connectionGeorgia Power's 2019 general base rate case.
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.
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The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the triennial Integrated Resource Plannuclear option at a future generation site in 2016.Stewart County, Georgia. The switch to natural gas astiming of cost recovery will be determined by the primary fuel is completeGeorgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.this time.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. Georgia Power expects to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.
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 Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Nuclear Construction
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction"Fuel Cost Recovery" of Georgia Power in Item 7 andof 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 reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.
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 and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein 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 pending litigation.the Contractor Settlement Agreement (as defined below).
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 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 that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims isguarantees, subject to a cap. 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 payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.)WECTEC under the Vogtle 3 and 4 Agreement arewere originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (a(which is now a subsidiary of Chicago Bridge & Iron Company, N.V.)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 certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, 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 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 NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. 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 are expected as construction proceeds.
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars).The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of
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April 2016 and April 2017 forIn 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars). In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.
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 certified 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's eighth VCM report filed in 2013Power 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) entered into bybetween Georgia Power and the Georgia PSC staffStaff (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. The
On April 15, 2015, the Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.
On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).
Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistentissued a procedural order in connection with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.
On February 27, 2015, Georgia Power filed its twelfth VCM report, with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner'sVogtle Owner's costs associated with the proposed 18-month
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.
Georgia Power will continue Pursuant to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued aPSC's procedural order in connection with the twelfth VCM report. Pursuant to this 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. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
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 for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; 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 $250 million had been paid as of June 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.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance 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-service capital cost and schedule are reasonable. The Staff is conducting a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement, and is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.1 billion had been incurred through June 30, 2016.
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 DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected tomatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in itslabor productivity, fabrication, assembly, delivery, and installation of plant equipment, the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
AdditionalFuture claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely tocould arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement but alsoand, under the enhanced dispute resolution procedures, may be resolved through litigation.litigation after the completion of nuclear fuel load for both units.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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.
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,management does not
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
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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.
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. Georgia Power expects to record charges of approximately $30 million during the remainder of 2016. Such charges 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, ContingentAsset Retirement Obligations, and Pension and Other Postretirement Benefits.Benefits, and Contingent Obligations.
Asset Retirement ObligationsRecently Issued Accounting Standards
AROs are computed asOn February 25, 2016, the fair valueFASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlaysexpense associated with leases and provides clarification regarding the asset retirements are discounted usingidentification of certain components of contracts that would represent a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning
The liability for AROs primarily relates to the decommissioning of Georgia Power's nuclear facilities, which include Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Georgia Power has retirement obligations related to various landfill sites, underground storage tanks, and asbestos removal. Georgia Power also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with Georgia Power's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Georgia Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Georgia Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" and "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
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Recently Issuedafter December 15, 2018, with early adoption permitted. Georgia Power is currently evaluating 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 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 Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises(ASU 2016-09). ASU 2016-09 changes the accounting for revenue recognition effectiveincome taxes and the cash flow presentation for fiscal years beginning after December 15, 2017.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 continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costscurrently recognizes any excess tax benefits and deficiencies related to a recognized debt liability be presentedthe exercise and vesting of stock compensation in the balance sheet as a direct deduction from the carrying amount of that debt liability andadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2015.2016. Early adoption is permitted and Georgia Power currently reflects unamortized debt issuance costsintends to adopt the ASU in other deferred charges and assets on its balance sheet. Uponthe fourth quarter 2016. The adoption the reclassification willis not expected to have a material impact on the results of operations, financial position, or cash flows of Georgia Power.
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 June 30, 2015.2016. 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 "Capital"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $774 million$1.17 billion for the first six months of 20152016 compared to $843$774 million for the corresponding period in 2014.2015. The decreaseincrease was primarily due to lower operating revenues, partially offset by increased fuel cost recovery.the timing of vendor payments. Net cash used for investing activities totaled $891 million$1.17 billion for the first six months of 20152016 compared to $917$891 million for the corresponding period in 20142015 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 $117$55 million for the first six months of 20152016 compared to $90$117 million in the corresponding period in 2014.2015. The increasedecrease in cash provided from financing activities is primarily due to an increase in short-termmaturities of long-term debt, borrowings. Fluctuations in cash flowhigher common stock dividends, and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, partially offset by senior note issuances and higher capital contributions received from Southern Company. 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 six months of 20152016 include increases of $468 millionan increase in property, plant, and equipment of $897 million to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $550$656 million and $231other regulatory assets, deferred of $372 million primarily related to changes in short-term debt and long-term debt, respectively, to fund the continuous construction program andash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" herein for general corporate purposes.additional information regarding changes in ash pond closure strategy.
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 $1.7 billion$658 million will be required through June 30, 20162017 to fund maturities and announced redemptions of long-term debt. See "Sources"Sources of Capital"Capital" herein for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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; 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"Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" herein for information regarding additional factors that may impact construction expenditures.
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. 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.
In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which 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 June 30, 20152016 would allow for borrowings of up to $2.2$2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $1.8$2.5 billion. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail"Retail Regulatory Matters – Georgia Power – Nuclear Construction"Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
As of June 30, 2015,2016, Georgia Power's current liabilities exceeded current assets by $1.3 billion$783 million primarily due to approximately $1.9 billionscheduled maturities of long-term debt due within one year and notes payable. For the remainder of 2015,debt. Georgia Power expects to utilize borrowings through the FFB as the primary source of long-term borrowed funds. Georgia Power also intends to utilize operating cash flows, as well as FFB borrowings, commercial paper, lines of credit, bank notes, and external securities issuances, as market conditions permit, and equity contributions from Southern Company 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 June 30, 2015,2016, Georgia Power had approximately $24$121 million of cash and cash equivalents. CommittedGeorgia Power's committed credit arrangementsarrangement with banks at June 30, 2015 were2016 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. Georgia Power is currently in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as follows:needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
|
| | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | Due Within One Year |
| 2016 | | 2018 | | Total | | Unused | | Term Out | | No Term Out |
| (in millions) | | (in millions) | | (in millions) |
| $ | 150 |
| | $ | 1,600 |
| | $ | 1,750 |
| | $ | 1,737 |
| | $ | — |
| | $ | 150 |
|
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"Bank Credit Arrangements"Arrangements" herein for additional information.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 20152016 was approximately $970$868 million. In addition, at June 30, 2015,2016, Georgia Power had $122$212 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Georgia Power. Such cross default provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness or guarantee obligations over a specified threshold. Georgia Power is currently 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, Georgia Power expects to renew or replace its credit arrangements, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
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 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 June 30, 2015 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Commercial paper | | $ | 200 |
| | 0.3 | % | | $ | 370 |
| | 0.3 | % | | $ | 598 |
|
| Short-term bank debt | | — |
| | — | % | | 247 |
| | 0.8 | % | | 250 |
|
| Total | | $ | 200 |
| | 0.3 | % | | $ | 617 |
| | 0.5 | % | | |
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 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 | | $ | 197 |
| | 0.8 | % | | $ | 164 |
| | 0.8 | % | | $ | 443 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.2016. |
Georgia Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, short-term bank notes, and operating cash flows.
Credit Rating Risk
Georgia 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.
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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, interest rate derivatives,transmission, and construction of new generation.generation at Plant Vogtle Units 3 and 4.
The maximum potential collateral requirements under these contracts at June 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential
Collateral
Requirements | Maximum Potential
Collateral
Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 102 |
| $ | 87 |
|
| Below BBB- and/or Baa3 | 1,341 |
| $ | 1,288 |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral
GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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'sPower to access capital markets and would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Georgia Power) on CreditWatch with negative implications.cost at which it does so.
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 2015,2016, Georgia Power entered into aissued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. 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 three-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were usedof 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 working capital and other general corporate purposes, and the loan was repaid at maturity.including Georgia Power's continuous construction program.
In April 2015,2016, Georgia Power purchased and held $65Power's $250 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power reoffered these bonds to the public in May 2015.
In April 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80%2011B 3.00% Senior Notes due April 15, 2035.
In May 2015, Georgia Power reoffered to the public $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by Georgia Power since 2013.matured.
In June 2015,2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600$300 million. The interest rate applicable to the $600$300 million principal amount is 3.283%2.571% for an interest period that extends to 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. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.
Subsequent to June 30, 2015, $97.925 million aggregate principal amount of the Development Authority of Putnam County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Branch Project), First Series 1996, First Series 1997, Second Series 1997, and First Series 1998 were redeemed.
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 June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 |
| 2014 | | 2015 | | 2014 | 2016 |
| 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 327 |
| | $ | 310 |
| | $ | 620 |
| | $ | 613 |
| $ | 319 |
| | $ | 327 |
| | $ | 602 |
| | $ | 620 |
|
| Wholesale revenues, non-affiliates | 27 |
| | 34 |
| | 52 |
| | 70 |
| 15 |
| | 27 |
| | 31 |
| | 52 |
|
| Wholesale revenues, affiliates | 13 |
| | 24 |
| | 35 |
| | 76 |
| 15 |
| | 13 |
| | 36 |
| | 35 |
|
| Other revenues | 17 |
| | 16 |
| | 34 |
| | 32 |
| 16 |
| | 17 |
| | 31 |
| | 34 |
|
| Total operating revenues | 384 |
| | 384 |
| | 741 |
| | 791 |
| 365 |
| | 384 |
| | 700 |
| | 741 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 122 |
| | 145 |
| | 232 |
| | 314 |
| 107 |
| | 122 |
| | 201 |
| | 232 |
|
| Purchased power, non-affiliates | 25 |
| | 14 |
| | 50 |
| | 30 |
| 32 |
| | 25 |
| | 62 |
| | 50 |
|
| Purchased power, affiliates | 9 |
| | 9 |
| | 17 |
| | 16 |
| 4 |
| | 9 |
| | 5 |
| | 17 |
|
| Other operations and maintenance | 91 |
| | 82 |
| | 185 |
| | 164 |
| 77 |
| | 91 |
| | 155 |
| | 185 |
|
| Depreciation and amortization | 40 |
| | 39 |
| | 60 |
| | 71 |
| 42 |
| | 40 |
| | 80 |
| | 60 |
|
| Taxes other than income taxes | 28 |
| | 26 |
| | 56 |
| | 53 |
| 29 |
| | 28 |
| | 58 |
| | 56 |
|
| Total operating expenses | 315 |
| | 315 |
| | 600 |
| | 648 |
| 291 |
| | 315 |
| | 561 |
| | 600 |
|
| Operating Income | 69 |
| | 69 |
| | 141 |
| | 143 |
| 74 |
| | 69 |
| | 139 |
| | 141 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 3 |
| | 3 |
| | 8 |
| | 5 |
| — |
| | 3 |
| | — |
| | 8 |
|
| Interest expense, net of amounts capitalized | (12 | ) | | (13 | ) | | (26 | ) | | (27 | ) | (12 | ) | | (12 | ) | | (25 | ) | | (26 | ) |
| Other income (expense), net | (1 | ) | | (1 | ) | | (2 | ) | | (1 | ) | (1 | ) | | (1 | ) | | (2 | ) | | (2 | ) |
| Total other income and (expense) | (10 | ) | | (11 | ) | | (20 | ) | | (23 | ) | (13 | ) | | (10 | ) | | (27 | ) | | (20 | ) |
| Earnings Before Income Taxes | 59 |
| | 58 |
| | 121 |
| | 120 |
| 61 |
| | 59 |
| | 112 |
| | 121 |
|
| Income taxes | 21 |
| | 22 |
| | 44 |
| | 45 |
| 24 |
| | 21 |
| | 44 |
| | 44 |
|
| Net Income | 38 |
| | 36 |
| | 77 |
| | 75 |
| 37 |
| | 38 |
| | 68 |
| | 77 |
|
| Dividends on Preference Stock | 3 |
| | 2 |
| | 5 |
| | 4 |
| 3 |
| | 3 |
| | 5 |
| | 5 |
|
| Net Income After Dividends on Preference Stock | $ | 35 |
| | $ | 34 |
| | $ | 72 |
| | $ | 71 |
| $ | 34 |
| | $ | 35 |
| | $ | 63 |
| | $ | 72 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income | $ | 38 |
| | $ | 36 |
| | $ | 77 |
| | $ | 75 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 38 |
| | $ | 36 |
| | $ | 77 |
| | $ | 75 |
|
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 Six Months
Ended June 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 77 |
| | $ | 75 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 64 |
| | 75 |
|
| Deferred income taxes | 40 |
| | 20 |
|
| Allowance for equity funds used during construction | (8 | ) | | (5 | ) |
| Other, net | 11 |
| | 1 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (15 | ) | | (57 | ) |
| -Fossil fuel stock | 6 |
| | 39 |
|
| -Prepaid income taxes | 12 |
| | 9 |
|
| -Other current assets | 1 |
| | 2 |
|
| -Accounts payable | (9 | ) | | 1 |
|
| -Accrued taxes | 15 |
| | 12 |
|
| -Accrued compensation | (10 | ) | | — |
|
| -Over recovered regulatory clause revenues | — |
| | 9 |
|
| -Other current liabilities | (1 | ) | | (4 | ) |
| Net cash provided from operating activities | 183 |
| | 177 |
|
| Investing Activities: | | | |
| Property additions | (148 | ) | | (159 | ) |
| Cost of removal, net of salvage | (7 | ) | | (6 | ) |
| Other investing activities | (19 | ) | | (5 | ) |
| Net cash used for investing activities | (174 | ) | | (170 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 4 |
| | 3 |
|
| Proceeds — | | | |
| Common stock issued to parent | 20 |
| | 50 |
|
| Pollution control revenue bonds | — |
| | 42 |
|
| Short-term borrowings | 40 |
| | — |
|
| Redemptions — Pollution control revenue bonds | — |
| | (29 | ) |
| Payment of preference stock dividends | (5 | ) | | (5 | ) |
| Payment of common stock dividends | (65 | ) | | (62 | ) |
| Other financing activities | 2 |
| | 2 |
|
| Net cash provided from (used for) financing activities | (4 | ) | | 1 |
|
| Net Change in Cash and Cash Equivalents | 5 |
| | 8 |
|
| Cash and Cash Equivalents at Beginning of Period | 39 |
| | 22 |
|
| Cash and Cash Equivalents at End of Period | $ | 44 |
| | $ | 30 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $3 and $2 capitalized for 2015 and 2014, respectively) | $ | 26 |
| | $ | 26 |
|
| Income taxes, net | (9 | ) | | 17 |
|
| Noncash transactions — Accrued property additions at end of period | 28 |
| | 31 |
|
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 June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 44 |
| | $ | 39 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 93 |
| | 73 |
|
| Unbilled revenues | | 77 |
| | 58 |
|
| Under recovered regulatory clause revenues | | 38 |
| | 57 |
|
| Other accounts and notes receivable | | 9 |
| | 8 |
|
| Affiliated companies | | 4 |
| | 10 |
|
| Accumulated provision for uncollectible accounts | | (2 | ) | | (2 | ) |
| Fossil fuel stock, at average cost | | 95 |
| | 101 |
|
| Materials and supplies, at average cost | | 55 |
| | 56 |
|
| Other regulatory assets, current | | 72 |
| | 74 |
|
| Prepaid expenses | | 35 |
| | 40 |
|
| Other current assets | | 3 |
| | 2 |
|
| Total current assets | | 523 |
| | 516 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,600 |
| | 4,495 |
|
| Less accumulated provision for depreciation | | 1,234 |
| | 1,296 |
|
| Plant in service, net of depreciation | | 3,366 |
| | 3,199 |
|
| Other utility plant, net | | 77 |
| | — |
|
| Construction work in progress | | 387 |
| | 465 |
|
| Total property, plant, and equipment | | 3,830 |
| | 3,664 |
|
| Other Property and Investments | | 15 |
| | 15 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 59 |
| | 56 |
|
| Other regulatory assets, deferred | | 406 |
| | 416 |
|
| Other deferred charges and assets | | 41 |
| | 41 |
|
| Total deferred charges and other assets | | 506 |
| | 513 |
|
| Total Assets | | $ | 4,874 |
| | $ | 4,708 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 37 |
| | $ | 38 |
| | $ | 68 |
| | $ | 77 |
|
| Other comprehensive income (loss): | | | | | | | |
| Qualifying hedges: | | | | | | | |
| Changes in fair value, net of tax of $(1), $-, $(3), and $-, respectively | (1 | ) | | — |
| | (4 | ) | | — |
|
| Total other comprehensive income (loss) | (1 | ) | | — |
| | (4 | ) | | — |
|
| Comprehensive Income | $ | 36 |
| | $ | 38 |
| | $ | 64 |
| | $ | 77 |
|
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.
GULF POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Notes payable | | $ | 154 |
| | $ | 110 |
|
| Accounts payable — | | | | |
| Affiliated | | 72 |
| | 87 |
|
| Other | | 52 |
| | 56 |
|
| Customer deposits | | 36 |
| | 35 |
|
| Other accrued taxes | | 24 |
| | 9 |
|
| Accrued interest | | 10 |
| | 11 |
|
| Accrued compensation | | 13 |
| | 23 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Liabilities from risk management activities | | 32 |
| | 37 |
|
| Other current liabilities | | 21 |
| | 23 |
|
| Total current liabilities | | 436 |
| | 413 |
|
| Long-term Debt | | 1,370 |
| | 1,370 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 852 |
| | 800 |
|
| Employee benefit obligations | | 119 |
| | 121 |
|
| Other cost of removal obligations | | 222 |
| | 235 |
|
| Other regulatory liabilities, deferred | | 49 |
| | 49 |
|
| Deferred capacity expense | | 152 |
| | 163 |
|
| Other deferred credits and liabilities | | 187 |
| | 101 |
|
| Total deferred credits and other liabilities | | 1,581 |
| | 1,469 |
|
| Total Liabilities | | 3,387 |
| | 3,252 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — June 30, 2015: 5,642,717 shares | | | | |
| — December 31, 2014: 5,442,717 shares | | 503 |
| | 483 |
|
| Paid-in capital | | 564 |
| | 560 |
|
| Retained earnings | | 274 |
| | 267 |
|
| Accumulated other comprehensive loss | | (1 | ) | | (1 | ) |
| Total common stockholder's equity | | 1,340 |
| | 1,309 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,874 |
| | $ | 4,708 |
|
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 68 |
| | $ | 77 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 83 |
| | 64 |
|
| Deferred income taxes | 16 |
| | 40 |
|
| Other, net | (3 | ) | | 3 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | (6 | ) | | (15 | ) |
| -Fossil fuel stock | 34 |
| | 6 |
|
| -Prepaid income taxes | 2 |
| | 12 |
|
| -Other current assets | (1 | ) | | 1 |
|
| -Accounts payable | (7 | ) | | (9 | ) |
| -Accrued taxes | 17 |
| | 15 |
|
| -Accrued compensation | (12 | ) | | (10 | ) |
| -Other current liabilities | 4 |
| | (1 | ) |
| Net cash provided from operating activities | 195 |
| | 183 |
|
| Investing Activities: | | | |
| Property additions | (68 | ) | | (148 | ) |
| Cost of removal, net of salvage | (4 | ) | | (7 | ) |
| Change in construction payables | (7 | ) | | (15 | ) |
| Other investing activities | (5 | ) | | (4 | ) |
| Net cash used for investing activities | (84 | ) | | (174 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 46 |
| | 4 |
|
| Proceeds — | | | |
| Common stock issued to parent | — |
| | 20 |
|
| Short-term borrowings | — |
| | 40 |
|
| Redemptions and repurchases — Senior notes | (125 | ) | | — |
|
| Payment of common stock dividends | (60 | ) | | (65 | ) |
| Other financing activities | — |
| | (3 | ) |
| Net cash used for financing activities | (139 | ) | | (4 | ) |
| Net Change in Cash and Cash Equivalents | (28 | ) | | 5 |
|
| Cash and Cash Equivalents at Beginning of Period | 74 |
| | 39 |
|
| Cash and Cash Equivalents at End of Period | $ | 46 |
| | $ | 44 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (net of $- and $3 capitalized for 2016 and 2015, respectively) | $ | 28 |
| | $ | 26 |
|
| Income taxes, net | (3 | ) | | (9 | ) |
| Noncash transactions — Accrued property additions at end of period | 13 |
| | 28 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 46 |
| | $ | 74 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 81 |
| | 76 |
|
| Unbilled revenues | | 77 |
| | 54 |
|
| Under recovered regulatory clause revenues | | 5 |
| | 20 |
|
| Income taxes receivable, current | | — |
| | 27 |
|
| Other accounts and notes receivable | | 3 |
| | 9 |
|
| Affiliated companies | | 10 |
| | 1 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock, at average cost | | 74 |
| | 108 |
|
| Materials and supplies, at average cost | | 56 |
| | 56 |
|
| Other regulatory assets, current | | 65 |
| | 90 |
|
| Other current assets | | 17 |
| | 22 |
|
| Total current assets | | 433 |
| | 536 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 5,032 |
| | 5,045 |
|
| Less accumulated provision for depreciation | | 1,351 |
| | 1,296 |
|
| Plant in service, net of depreciation | | 3,681 |
| | 3,749 |
|
| Other utility plant, net | | — |
| | 62 |
|
| Construction work in progress | | 68 |
| | 48 |
|
| Total property, plant, and equipment | | 3,749 |
| | 3,859 |
|
| Other Property and Investments | | 4 |
| | 4 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 60 |
| | 61 |
|
| Other regulatory assets, deferred | | 523 |
| | 427 |
|
| Other deferred charges and assets | | 49 |
| | 33 |
|
| Total deferred charges and other assets | | 632 |
| | 521 |
|
| Total Assets | | $ | 4,818 |
| | $ | 4,920 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 195 |
| | $ | 110 |
|
| Notes payable | | 187 |
| | 142 |
|
| Accounts payable — | | | | |
| Affiliated | | 46 |
| | 55 |
|
| Other | | 44 |
| | 44 |
|
| Customer deposits | | 36 |
| | 36 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 5 |
| | 4 |
|
| Other accrued taxes | | 25 |
| | 9 |
|
| Accrued interest | | 8 |
| | 9 |
|
| Accrued compensation | | 13 |
| | 25 |
|
| Deferred capacity expense, current | | 22 |
| | 22 |
|
| Other regulatory liabilities, current | | 19 |
| | 22 |
|
| Liabilities from risk management activities | | 32 |
| | 49 |
|
| Other current liabilities | | 30 |
| | 40 |
|
| Total current liabilities | | 662 |
| | 567 |
|
| Long-term Debt | | 987 |
| | 1,193 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 905 |
| | 893 |
|
| Employee benefit obligations | | 126 |
| | 129 |
|
| Deferred capacity expense | | 130 |
| | 141 |
|
| Asset retirement obligations | | 128 |
| | 113 |
|
| Other cost of removal obligations | | 237 |
| | 233 |
|
| Other regulatory liabilities, deferred | | 46 |
| | 47 |
|
| Other deferred credits and liabilities | | 90 |
| | 102 |
|
| Total deferred credits and other liabilities | | 1,662 |
| | 1,658 |
|
| Total Liabilities | | 3,311 |
| | 3,418 |
|
| Preference Stock | | 147 |
| | 147 |
|
| Common Stockholder's Equity: | | | | |
| Common stock, without par value — | | | | |
| Authorized — 20,000,000 shares | | | | |
| Outstanding — June 30, 2016: 5,642,717 shares | | | | |
| — December 31, 2015: 5,642,717 shares | | 503 |
| | 503 |
|
| Paid-in capital | | 573 |
| | 567 |
|
| Retained earnings | | 288 |
| | 285 |
|
| Accumulated other comprehensive loss | | (4 | ) | | — |
|
| Total common stockholder's equity | | 1,360 |
| | 1,355 |
|
| Total Liabilities and Stockholder's Equity | | $ | 4,818 |
| | $ | 4,920 |
|
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
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Gulf Power operates as a vertically integrated utility providing electricity 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. 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, and fuel. AppropriatelyEffectively 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. Capacity revenues represent
Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements forThe revenues from wholesale contracts covering 100% of Gulf Power's co-ownership of Plant Scherer Unit 3 (205 MWs) through 2015 and 41% through 2019. Thesethis capacity revenues represented 82% of total wholesale capacity revenues for 2014.in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power is actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, butPower's remaining contracted sales from the unit will cover approximately 24% of the unit through 2019. The expiration of currentthese contracts couldwill have a material negative impact on Gulf Power's earnings.earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.
In 2013, the Florida PSC voted to approve a settlement agreement (Rate Case Settlement Agreement) related to Gulf Power's retail base rate case. Under the terms of the Rate Case Settlement Agreement, Gulf Power is authorized to reduce depreciation and record a regulatory asset as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017, of which $34.9 million had been recorded as of June 30, 2016, and to accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until January 1, 2017. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters– Retail Base Rate Case" herein for additional details of the Rate Case Settlement Agreement.
Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.9 | | $1 | | 1.4 |
Gulf Power's net income after dividends on preference stock for the second quarter 2015 was $35 million compared to $34 million for the corresponding period in 2014. The increase was primarily due to higher retail revenues related to a base rate increase, partially offset by higher operations and maintenance expenses.
Gulf Power's net income after dividends on preference stock for year-to-date 2015 was $72 million compared to $71 million for the corresponding period in 2014. The increase was primarily due to a reduction in depreciation, as authorized by the Florida PSC, and higher retail revenues related to a base rate increase, partially offset by higher operations and maintenance expenses.
Retail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 5.5 | | $7 | | 1.1 |
In the second quarter 2015, retail revenues were $327 million compared to $310 million for the corresponding period in 2014. For year-to-date 2015, retail revenues were $620 million compared to $613 million for the corresponding period in 2014.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Net Income
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (2.9) | | $(9) | | (12.5) |
Gulf Power's net income after dividends on preference stock for the second quarter 2016 was $34 million compared to $35 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues, partially offset by lower operations and maintenance expenses.
Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $63 million compared to $72 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
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(8) | | (2.4) | | $(18) | | (2.9) |
In the second quarter 2016, retail revenues were $319 million compared to $327 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $602 million compared to $620 million for the corresponding period in 2015.
Details of the changes in retail revenues were as follows:
| | | | | Second Quarter
2015 | | Year-to-Date 2015 | Second Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) | | (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 310 |
| | | | $ | 613 |
| | | $ | 327 |
| | | | $ | 620 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | 7 |
| | 2.3 |
| | 10 |
| | 1.7 |
| 9 |
| | 2.8 |
| | 17 |
| | 2.7 |
|
| Sales growth | | 2 |
| | 0.6 |
| | — |
| | — |
| |
| Sales growth (decline) | | (1 | ) | | (0.3 | ) | | 1 |
| | 0.2 |
|
| Weather | | 4 |
| | 1.3 |
| | 4 |
| | 0.6 |
| (2 | ) | | (0.6 | ) | | (7 | ) | | (1.1 | ) |
| Fuel and other cost recovery | | 4 |
| | 1.3 |
| | (7 | ) | | (1.2 | ) | (14 | ) | | (4.3 | ) | | (29 | ) | | (4.7 | ) |
| Retail – current year | | $ | 327 |
| | 5.5 | % | | $ | 620 |
| | 1.1 | % | $ | 319 |
| | (2.4 | )% | | $ | 602 |
| | (2.9 | )% |
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 second quarter and year-to-date 20152016 when compared to the corresponding periods in 20142015 primarily due to an increase in retail base rates effective in January 2015, as authorized in a settlement agreement for Gulf Power's 2013 base rate case, and higher revenues associated with an increase in the environmental andcost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause ratesrate, both effective in January 2016.
Revenues attributable to changes in sales decreased slightly in the second quarter 2016 when compared to the corresponding period in 2015. For the second quarter 2016, weather-adjusted KWH sales to residential and commercial customers decreased 1.3% and 2.6%, respectively, due to lower customer usage, partially offset by
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
customer growth. KWH sales to industrial customers increased 1.2% for the second quarter 2016 primarily due to decreased customer co-generation, partially offset by changes in customers' operations.
Revenues attributable to changes in sales increased in the second quarter 2015slightly year-to-date 2016 when compared to the corresponding period in 2014.2015. Weather-adjusted KWH energy sales to residential and commercial customers increased 3.0% and 1.6%, respectively,0.6% due to customer growth, and higherpartially offset by lower customer usage. Weather-adjusted KWH energy sales to industrial customers decreased 2.8% primarily due to increased customer co-generation.
Revenues attributable to changes in sales remained essentially flat year-to-date 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.9% and 0.1%, respectively,1.4% due to lower customer usage, partially offset by customer growth. KWH energy sales to industrial customers decreased 2.7%increased 3.9% primarily due to increaseddecreased customer co-generation.co-generation, partially offset by changes in customers' operations.
Fuel and other cost recovery revenues increaseddecreased in the second quarter 2015and year-to-date 2016 when compared to the corresponding periodperiods in 20142015, primarily due to higher revenues associated with increased recoverable purchased power capacity costs, partially offset by lower revenues associated with fuel costs as the result of decreased generation and lower purchased power energy costs. For year-to-date 2015, fuel and other cost recovery revenues decreased when compared to the corresponding perioda decrease in 2014 primarily due to lower revenues associated with fuel costs as a result of decreased generation and lower purchased power energy costs, partially offset by higher revenues associated with purchased power capacity costs.
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 – Non-Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(7) | | (20.6) | | $(18) | | (25.7) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(12) | | (44.4) | | $(21) | | (40.4) |
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 wholesale earnings. Energynet income. The energy is generally sold at variable cost and does not have a significant impact on wholesale earnings.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 service territory, and the availability of the Southern Company system's generation.
In the second quarter 2015,2016, wholesale revenues from sales to non-affiliates were $27$15 million compared to $34$27 million for the corresponding period in 2014.2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $31 million compared to $52 million for the corresponding period in 2015. These decreases were primarily due to a 52.5% and 47.6% decrease for the second quarter and year-to-date 2016, respectively, in capacity revenues resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (15 | ) | | (12.3 | ) | | $ | (31 | ) | | (13.4 | ) |
| Purchased power – non-affiliates | | 7 |
| | 28.0 |
| | 12 |
| | 24.0 |
|
| Purchased power – affiliates | | (5 | ) | | (55.6 | ) | | (12 | ) | | (70.6 | ) |
| Total fuel and purchased power expenses | | $ | (13 | ) | | | | $ | (31 | ) | | |
In the second quarter 2016, total fuel and purchased power expenses were $143 million compared to $156 million for the corresponding period in 2015. The decrease was primarily due to a 43.5% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.
For year-to-date 2015, wholesale revenues from sales to non-affiliates were $52$14 million compared to $70 million for the corresponding period in 2014. The decrease was primarily due to a 52.1% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer-owned generation.
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (45.8) | | $(41) | | (53.9) |
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 second quarter 2015, wholesale revenues from sales to affiliates were $13 million compared to $24 million for the corresponding period in 2014. The decrease was primarily due to a 29.9% decrease in KWH sales that resulted from planned outages for Gulf Power generation resources and a 20.6% decrease in the priceaverage cost of energy sold to affiliates due tofuel and purchased power as a result of lower power pool interchange rates resultinggeneration from lower natural gas prices.Gulf Power's coal-fired resources.
For year-to-date 2015, wholesale revenues from sales to affiliates were $35 million compared to $76 million for the corresponding period in 2014. The decrease was primarily due to a 37.2% decrease in KWH sales that resulted from planned outages for Gulf Power generation resources and a 26.1% decrease in the price of energy sold to affiliates due to lower power pool interchange rates resulting from lower natural gas prices.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | | | | |
| | | Second Quarter 2015
vs.
Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 |
| | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (23 | ) | | (15.9 | ) | | $ | (82 | ) | | (26.1 | ) |
| Purchased power – non-affiliates | | 11 |
| | 78.6 |
| | 20 |
| | 66.7 |
|
| Purchased power – affiliates | | — |
| | — |
| | 1 |
| | 6.3 |
|
| Total fuel and purchased power expenses | | $ | (12 | ) | | | | $ | (61 | ) | | |
In the second quarter 2015,For year-to-date 2016, total fuel and purchased power expenses were $156$268 million compared to $168$299 million for the corresponding period in 2014.2015. The decrease was primarily the result of a $9$37 million decrease in the volume of KWHs generated and purchased due to planned outages for Gulf Power's generation and a resource contracted under a PPA and a $3 million net decrease due to the lower average cost of fuel and purchased power.
For year-to-date 2015, total fuel and purchased power expenses were $299 million compared to $360 million for the corresponding period in 2014. The decrease was primarily theas a result of lower generation from Gulf Power's coal-fired resources, partially offset by a $50$6 million decrease inincrease related to the volume of KWHs generated and purchased due to planned outages for Gulf Power's generation and a resource contracted under a PPA and an $11 million net decrease due to the lower average cost of fuel and purchased power.purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel cost and purchased power capacity cost recovery clauses.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.
Details of Gulf Power's generation and purchased power were as follows:
| | | | | Second Quarter
2015 | | Second Quarter
2014 | | Year-to-Date 2015 | | Year-to-Date 2014 | Second Quarter 2016 | | Second Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (millions of KWHs) | | 2,360 | | 2,670 | | 4,596 | | 5,632 | 2,064 | | 2,360 | | 3,880 | | 4,596 |
Total purchased power (millions of KWHs) | | 1,336 | | 1,281 | | 2,594 | | 2,711 | 1,629 | | 1,336 | | 3,389 | | 2,594 |
Sources of generation (percent) – | | |
| Coal | | 61 | | 69 | | 60 | | 70 | 54 | | 61 | | 48 | | 60 |
| Gas | | 39 | | 31 | | 40 | | 30 | 46 | | 39 | | 52 | | 40 |
Cost of fuel, generated (cents per net KWH) – | | |
| Coal | | 4.05 | | 4.09 | | 4.02 | | 4.21 | 4.14 | | 4.05 | | 4.05 | | 4.02 |
| Gas | | 4.38 | | 3.99 | | 4.17 | | 3.82 | 4.11 | | 4.38 | | 3.92 | | 4.17 |
Average cost of fuel, generated (cents per net KWH) | | 4.18 | | 4.06 | | 4.08 | | 4.09 | 4.12 | | 4.18 | | 3.98 | | 4.08 |
Average cost of purchased power (cents per net KWH)(*) | | 4.25 | | 4.71 | | 4.31 | | 4.75 | 3.50 | | 4.25 | | 3.35 | | 4.31 |
| |
| (*) | Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2015,2016, fuel expense was $122$107 million compared to $145$122 million for the corresponding period in 2014.2015. The decrease was primarily due to an 11.6%a 22.5% decrease in the volume of KWHs generated due to planned outages forby Gulf Power's coal-fired generation resources and a resource contracted under a PPA. This was partially offset by a 3.0% increase1.4% decrease in the average cost of fuel. The decreases were partially offset by a 2.8% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
For year-to-date 2016, fuel expense was $201 million compared to $232 million for the corresponding period in 2015. The decrease was primarily due to higher natural gas pricesa 31.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 2.5% decrease in the average cost of fuel. The decreases were partially offset by a 7.7% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.
Purchased Power – Non-Affiliates
In the second quarter 2016, purchased power expense from non-affiliates was $32 million compared to $25 million for the corresponding period in 2015. The increase was primarily due to a 49.9% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 25.8% decrease in the average cost per KWH generated, which includes firm gas transportationpurchased due to lower energy costs from gas-fired and storage.wind market resources.
For year-to-date 2016, purchased power expense from non-affiliates was $62 million compared to $50 million for the corresponding period in 2015. The increase was primarily due to a 61.8% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 29.2% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired and wind market resources.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015, fuel expense was $232 million compared to $314 million for the corresponding period in 2014. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated due to planned outages for Gulf Power's generation and a resource contracted under a PPA.
Purchased Power – Non-Affiliates
In the second quarter 2015, purchased power expense from non-affiliates was $25 million compared to $14 million for the corresponding period in 2014. The increase was primarily due to a $10 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 7.9% decrease in the volume of KWHs purchased due to a planned outage for a resource contracted under a PPA.
For year-to-date 2015, purchased power expense from non-affiliates was $50 million compared to $30 million for the corresponding period in 2014. The increase was primarily due to a $26 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 17.4% decrease in the volume of KWHs purchased due to a planned outage for a resource contracted under a PPA.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2015 and the corresponding period in 2014,2016, purchased power expense from affiliates was $4 million compared to $9 million.million for the corresponding period in 2015. The decrease was primarily due to a 47.9% decrease in the volume of KWHs purchased increased 55.4% due to planned outages for Gulf Power's generationlower territorial loads resulting from milder weather and a resource contracted under a PPA. The increase was offset by a 39.1%22.7% decrease in the average cost per KWH purchased due to lower power pool interchange rates.rates as a result of lower natural gas prices and lower off-peak energy prices of renewable market resources.
For year-to-date 2015,2016, purchased power expense from affiliates was $17$5 million compared to $16$17 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to a 68.5% increase54.5% decrease in the volume of KWHs purchased due to planned outages for Gulf Power's generationlower territorial loads resulting from milder weather and a resource contracted under a PPA, largely offset by a 36.0%30.5% decrease in the average cost per KWH purchased due to lower power pool interchange rates.rates as a result of lower natural gas 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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $9 | | 11.0 | | $21 | | 12.8 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(14) | | (15.4) | | $(30) | | (16.2) |
In the second quarter 2015,2016, other operations and maintenance expenses were $91$77 million compared to $82$91 million for the corresponding period in 2014. The increase was primarily due to increases of $6 million in routine and planned maintenance expenses at generation and distribution facilities, $1 million in energy services expenses, $1 million in customer service expenses, and $1 million in employee benefits including pension costs.
2015. For year-to-date 2015,2016, other operations and maintenance expenses were $185$155 million compared to $164$185 million for the corresponding period in 2014. The increase was2015. These decreases were primarily due to increases of $11 milliondecreases in routine and planned maintenance expenses at generation facilities $2 million in energy servicesand lower expenses $2 million in customer service expenses, and $2 million in employee benefits including pension costs.related to marketing programs.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Expenses from energy services didmarketing programs do not have a significant impact on earnings since they wereare generally offset by associated revenues. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.energy conservation revenues through Gulf Power's energy conservation cost recovery clause.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $1 | | 2.6 | | $(11) | | (15.5) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 5.0 | | $20 | | 33.3 |
In the second quarter 2015,For year-to-date 2016, depreciation and amortization was $40$80 million compared to $39$60 million for the corresponding period in 2014.2015. The increase was primarily due to $13 million less of a reduction in depreciation and amortization was primarily attributablecompared to the corresponding period in 2015, as authorized in the Rate Case Settlement Agreement, as well as property additions at generation, transmission, and distribution facilities.
For year-to-date 2015, depreciation and amortization was $60 million compared to $71 million for the corresponding period in 2014. As authorized by the Florida PSC in a settlement agreement, Gulf Power recorded a $19.6 million reduction in depreciation in the first half of 2015 as compared to $5.4 million in the corresponding period in 2014. The decrease was partially offset by increases of $3 million primarily attributable to property additions at generation, transmission, and distribution facilities.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" of Gulf Power in Item 7 and 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"Retail Regulatory Matters – Gulf Power – Retail Base Rate Case"Case" herein for additional information.
Taxes Other Than Income Taxes
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $2 | | 7.7 | | $3 | | 5.7 |
In the second quarter 2015, taxes other than income taxes were $28 million compared to $26 million for the corresponding period in 2014. For year-to-date 2015, taxes other than income taxes were $56 million compared to $53 million for the corresponding period in 2014. The increases were primarily due to increases in property taxes, franchise fees, and gross receipts taxes. Franchise fees and gross receipts taxes have no impact on net income.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $3 | | 60.0 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | N/M | | $(8) | | N/M |
ForN/M - Not meaningful
In the second quarter and year-to-date 2015, 2016, AFUDC equity was $8 millionimmaterial compared to $5$3 million and $8 million for the corresponding periodperiods in 2014. The increase was2015, respectively. These decreases were primarily due to increased construction related to environmental control projects at generation facilities.facilities and transmission projects placed in service in 2015.
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. 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. Future earnings in the near term will depend, in part, upon maintaining and
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
growing sales which are subject to a number of 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, the rate of economic growth or decline in Gulf Power's service territory, and the successful remarketing of wholesale capacity as current contracts expire. ChangesDemand 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, may impact sales for Gulf Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth andwhich may impact future earnings. 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.
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 co-ownership of Plant Scherer Unit 3 (205 MWs) and consist of both capacity and energy sales. Capacity revenues represent the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's co-ownership of that unit through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively evaluating strategic alternatives related to this asset, including replacement wholesale contracts, but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.
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 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 regulatory or legislative changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified.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" andMatters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery"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
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule and the Cross State Air Pollution Rule (CSAPR).regional haze regulations.
On April 25, 2016, in response to a June 12, 2015 U.S. Supreme Court opinion, the EPA published a finalits supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule requiring affected states (including Florida, Georgia,compliance requirements, costs, or deadlines, and Mississippi)all Gulf Power units that are subject to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSMthe MATS rule have completed the measures necessary to achieve compliance with the MATS rule by no later than November 22, 2016.the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the final ruleproposed revisions will depend on the
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
outcome oftheir ultimate adoption, implementation, and any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Florida and Georgia. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
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 EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Gulf Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Gulf Power recorded incremental asset retirement obligations (ARO) of approximately $75 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates.
In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Gulf Power's AROs.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Gulf Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the final rules on Gulf Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
FERC Matters
Gulf Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Gulf Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Gulf Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Gulf Power) 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 operating companies (including Gulf Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
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 – Retail Base Rate Case"Matters" in Item 8 of the Form 10-K for additional information.
TableGulf Power's wholesale business consists of Contentstwo 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 (205 MWs) 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 will cover approximately 24% of the unit through 2019. The expiration of these contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Retail Base Rate Case
In December 2013, the Florida PSC approved a settlement agreementthe Rate Case Settlement Agreement that providesauthorized Gulf Power mayto reduce depreciation expense and record a regulatory asset up to $62.5 million betweenfrom January 2014 andthrough June 2017. In any given month, such depreciation expense 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. Gulf Power recognized a $19.6 million reduction in depreciation expense inFor 2014, 2015, and the first six months of 2015.2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Renewables
OnThe Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 16, 2015,15, 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.
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 has filed a petition with the Florida PSC approved three energy purchase agreements totaling 120 MWsrequesting permission to recover the remaining net book value of utility-scale solar generation located at three military installations in northwest Florida. On May 5, 2015,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. This amount is comprised of the reclassification of the net book value of these units from other utility plant, net and the associated materials and supplies, both as of March 31, 2016. The retirement of these units is not expected to have a material impact on Gulf Power's financial statements as Gulf Power expects to recover these amounts through its rates; however, the ultimate outcome depends on future rate proceedings with the Florida PSC approved an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. Purchases under these agreements willand cannot be for energy only and will be recovered through Gulf Power's fuel cost recovery mechanism.
Other Mattersdetermined at this time.
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)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGulf 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 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, Contingent Obligations, and Pension and Other Postretirement Benefits.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to Gulf Power's combustion turbines at its Pea Ridge facility and facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Gulf Power has retirement obligations related to various landfill sites, a barge unloading dock, asbestos removal, and disposal of polychlorinated biphenyls in certain transformers. Gulf Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Gulf Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Gulf Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Gulf Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Gulf Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and Note (A)estimates related to the Condensed Financial Statements under "AssetElectric Utility Regulation, Asset Retirement Obligations" herein for additional information.Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Gulf Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015,February 25, 2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30):Leases Simplifying the Presentation of Debt Issuance Costs(Topic 842) (ASU 2016-02). The ASU 2016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Gulf Power is currently evaluating 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 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 reflects unamortized debt issuance costsrecognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in other deferred chargesadditional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and assets on its balance sheet. UponGulf Power intends to adopt the ASU in the fourth quarter 2016. The adoption the reclassification willis not expected to have a material impact on the results of operations, financial position, or cash flows of Gulf Power.
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 June 30, 2015.2016. Gulf Power intends to continue to monitor its access to short-term and long-term
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $183$195 million for the first six months of 20152016 compared to $177$183 million for the corresponding period in 2014.2015. The $6$12 million increase in net cash was primarily due to increases in cash flows related to cost recovery clausesa federal income tax refund and an increase in deferred income taxes related to bonus depreciation, partially offset by decreases in the timing of fossil fuel stock purchases, accrued compensation, andpartially offset by increases in accounts payable.receivable. Net cash used for investing activities totaled $174$84 million in the first six months of 20152016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $4$139 million for the first six months of 20152016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by an increase in notes payable and the issuance of common stock to Southern Company. Fluctuations in cash flowpayable. 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 six months of 20152016 include increasesdecreases of $166$125 million in long-term debt due to a redemption and $110 million in net property, plant, and equipment $86 million in other deferred creditsprimarily due to the retirement of Plant Smith Units 1 and other liabilities primarily related to AROs associated with the CCR Rule, $52 million in accumulated deferred income tax liabilities primarily related to bonus depreciation, and $44 million in notes payable.2.
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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements, and unrecognized tax benefits.requirements. Approximately $60$195 million will be required through June 30, 20162017 to fund announced redemptionsmaturities of long-term debt. See "Financing Activities""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 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.
Sources of Capital
Gulf 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. 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, which can fluctuate significantly due to the seasonality of the business.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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
At June 30, 2015,2016, Gulf Power had approximately $44$46 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 20152016 were as follows:
| | | Expires | Expires | | | | | | Executable Term Loans | | Due Within One Year | Expires | | | | | | Executable Term Loans | | Due Within One Year |
| 2015 | | 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2016 | | 2016 | | 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) | | (in millions) | | (in millions) | | (in millions) |
| $ | 20 |
| | $ | 225 |
| | $ | 30 |
| | $ | 275 |
| | $ | 275 |
| | $ | 50 |
| | $ | — |
| | $ | 50 |
| | $ | 195 |
| 75 |
| | $ | 40 |
| | $ | 165 |
| | $ | 280 |
| | $ | 280 |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| | $ | 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"Bank Credit Arrangements"Arrangements" herein for additional information.
Most of the unused credit arrangements with banks is allocated to provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $69 million. In addition, at June 30, 2015, Gulf Power had approximately $46 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross defaultacceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross defaultacceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, or guarantee obligations over a specified threshold.the payment of which was then accelerated. Gulf Power is currently 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
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $82 million. In addition, at June 30, 2016, Gulf Power had approximately $21 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 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 June 30, 2015 | | Short-term Debt During the Period(*) | | Short-term Debt at June 30, 2016 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average 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 | | $ | 114 |
| | 0.3 | % | | $ | 133 |
| | 0.3 | % | | $ | 175 |
| | $ | 87 |
| | 0.8 | % | | $ | 62 |
| | 0.8 | % | | $ | 94 |
|
| Short-term bank debt | | 40 |
| | 1.3 | % | | 10 |
| | 1.3 | % | | 40 |
| | 100 |
| | 1.2 | % | | 54 |
| | 1.2 | % | | 100 |
|
| Total | | $ | 154 |
| | 0.6 | % | | $ | 143 |
| | 0.4 | % | | | | $ | 187 |
| | 1.0 | % | | $ | 116 |
| | 1.0 | % | | |
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.2016. |
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.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Credit Rating Risk
Gulf 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 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 June 30, 20152016 were as follows:
| | | Credit Ratings | Maximum Potential Collateral Requirements | Maximum Potential Collateral Requirements |
| | (in millions) | (in millions) |
| At BBB- and/or Baa3 | $ | 91 |
| $ | 137 |
|
| Below BBB- and/or Baa3 | 481 |
| $ | 526 |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, anya credit rating downgrade could impact the ability of Gulf Power's abilityPower to access capital markets particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which it does so.
Subsequent to June 30, 2015, S&P placed its ratings of Southern Company and the traditional operating companies (including Gulf Power) on CreditWatch with negative implications.
Market Price Risk
Gulf Power's market risk exposure relative to interest rate changes for the second quarter and year-to-date 20152016 has not changed materially compared to the December 31, 20142015 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.
For an in-depth 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 2015, Gulf Power issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portionis actively evaluating alternatives, including, without limitation, rededication of Gulf Power's short-term debtownership of Plant Scherer Unit 3 (205 MWs) to serve retail customers for whom it was originally planned and forbuilt, replacement long-term wholesale contracts or other general corporate purposes, includingsales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's continuous construction program.ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.
Financing Activities
In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 2015,1, 2051.
Also in May 2016, Gulf Power entered into a three-monthan 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $40$100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for credit support, working capital and other general corporate purposes.
Subsequent to June 30, 2015, Gulf Power purchased and held $13 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Refunding Bonds (Gulf Power Company Project), Series 2012. Gulf Power reoffered these bonds on July 16, 2015.
GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Subsequent to June 30, 2015, Gulf Power announced the redemption in September 2015 of $60 million aggregate principal amount of its Series L 5.65% Senior Notes due September 1, 2035.
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.
MISSISSIPPI POWER COMPANY
MISSISSIPPI POWER COMPANY
CONDENSED STATEMENTS OF OPERATIONSINCOME (UNAUDITED)
| | | | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Retail revenues | $ | 189 |
| | $ | 211 |
| | $ | 357 |
| | $ | 418 |
| $ | 206 |
| | $ | 189 |
| | $ | 389 |
| | $ | 357 |
|
| Wholesale revenues, non-affiliates | 63 |
| | 75 |
| | 141 |
| | 172 |
| 60 |
| | 63 |
| | 120 |
| | 141 |
|
| Wholesale revenues, affiliates | 18 |
| | 20 |
| | 45 |
| | 43 |
| 7 |
| | 18 |
| | 16 |
| | 45 |
|
| Other revenues | 5 |
| | 5 |
| | 9 |
| | 9 |
| 4 |
| | 5 |
| | 8 |
| | 9 |
|
| Total operating revenues | 275 |
| | 311 |
| | 552 |
| | 642 |
| 277 |
| | 275 |
| | 533 |
| | 552 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 115 |
| | 143 |
| | 229 |
| | 290 |
| 81 |
| | 115 |
| | 157 |
| | 229 |
|
| Purchased power, non-affiliates | 2 |
| | 1 |
| | 3 |
| | 13 |
| 1 |
| | 2 |
| | 1 |
| | 3 |
|
| Purchased power, affiliates | 2 |
| | 6 |
| | 4 |
| | 15 |
| 4 |
| | 2 |
| | 9 |
| | 4 |
|
| Other operations and maintenance | 68 |
| | 61 |
| | 144 |
| | 125 |
| 68 |
| | 68 |
| | 136 |
| | 144 |
|
| Depreciation and amortization | 30 |
| | 24 |
| | 57 |
| | 47 |
| 45 |
| | 30 |
| | 84 |
| | 57 |
|
| Taxes other than income taxes | 23 |
| | 20 |
| | 48 |
| | 41 |
| 25 |
| | 23 |
| | 50 |
| | 48 |
|
| Estimated loss on Kemper IGCC | 23 |
| | — |
| | 32 |
| | 380 |
| 81 |
| | 23 |
| | 134 |
| | 32 |
|
| Total operating expenses | 263 |
| | 255 |
| | 517 |
| | 911 |
| 305 |
| | 263 |
| | 571 |
| | 517 |
|
| Operating Income (Loss) | 12 |
| | 56 |
| | 35 |
| | (269 | ) | (28 | ) | | 12 |
| | (38 | ) | | 35 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Allowance for equity funds used during construction | 25 |
| | 37 |
| | 53 |
| | 75 |
| 30 |
| | 25 |
| | 59 |
| | 53 |
|
| Interest expense, net of amounts capitalized | 30 |
| | (13 | ) | | 19 |
| | (25 | ) | (15 | ) | | 30 |
| | (31 | ) | | 19 |
|
| Other income (expense), net | (1 | ) | | (1 | ) | | (2 | ) | | (4 | ) | (1 | ) | | (1 | ) | | (3 | ) | | (2 | ) |
| Total other income and (expense) | 54 |
| | 23 |
| | 70 |
| | 46 |
| 14 |
| | 54 |
| | 25 |
| | 70 |
|
| Earnings (Loss) Before Income Taxes | 66 |
| | 79 |
| | 105 |
| | (223 | ) | (14 | ) | | 66 |
| | (13 | ) | | 105 |
|
| Income taxes (benefit) | 16 |
| | 16 |
| | 20 |
| | (114 | ) | (17 | ) | | 16 |
| | (27 | ) | | 20 |
|
| Net Income (Loss) | 50 |
| | 63 |
| | 85 |
| | (109 | ) | |
| Net Income | | 3 |
| | 50 |
| | 14 |
| | 85 |
|
| Dividends on Preferred Stock | 1 |
| | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Net Income (Loss) After Dividends on Preferred Stock | $ | 49 |
| | $ | 62 |
| | $ | 84 |
| | $ | (110 | ) | |
| Net Income After Dividends on Preferred Stock | | $ | 2 |
| | $ | 49 |
| | $ | 13 |
| | $ | 84 |
|
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
|
| | | | | | | | | | | | | | | |
| | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 |
| | (in millions) | | (in millions) |
| Net Income (Loss) | $ | 50 |
| | $ | 63 |
| | $ | 85 |
| | $ | (109 | ) |
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
|
| Comprehensive Income (Loss) | $ | 50 |
| | $ | 63 |
| | $ | 85 |
| | $ | (109 | ) |
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 Six Months
Ended June 30, |
| | 2015 | | 2014 |
| | (in millions) |
| Operating Activities: | | | |
| Net income (loss) | $ | 85 |
| | $ | (109 | ) |
| Adjustments to reconcile net income (loss) to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 55 |
| | 50 |
|
| Deferred income taxes | 694 |
| | (108 | ) |
| Investment tax credits | 32 |
| | 28 |
|
| Allowance for equity funds used during construction | (53 | ) | | (75 | ) |
| Regulatory assets associated with Kemper IGCC | (50 | ) | | (26 | ) |
| Estimated loss on Kemper IGCC | 32 |
| | 380 |
|
| Income taxes receivable, non-current | (544 | ) | | — |
|
| Other, net | 8 |
| | 7 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 6 |
| | (32 | ) |
| -Fossil fuel stock | 5 |
| | 32 |
|
| -Prepaid income taxes | 24 |
| | (12 | ) |
| -Other current assets | (7 | ) | | (5 | ) |
| -Accounts payable | (25 | ) | | 4 |
|
| -Accrued taxes | (51 | ) | | (23 | ) |
| -Accrued interest | (7 | ) | | 13 |
|
| -Accrued compensation | (12 | ) | | 4 |
|
| -Over recovered regulatory clause revenues | 32 |
| | (18 | ) |
| -Mirror CWIP | 82 |
| | 67 |
|
| -Other current liabilities | 3 |
| | 1 |
|
| Net cash provided from operating activities | 309 |
| | 178 |
|
| Investing Activities: | | | |
| Property additions | (428 | ) | | (692 | ) |
| Construction payables | (15 | ) | | (28 | ) |
| Other investing activities | (17 | ) | | (13 | ) |
| Net cash used for investing activities | (460 | ) | | (733 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | 475 |
| | — |
|
| Proceeds — | | | |
| Capital contributions from parent company | 77 |
| | 211 |
|
| Bonds — Other | — |
| | 12 |
|
| Interest-bearing refundable deposit | — |
| | 75 |
|
| Long-term debt issuance to parent company | — |
| | 220 |
|
| Other long-term debt issuances | — |
| | 250 |
|
| Short-term borrowings | 30 |
| | — |
|
| Redemptions — Other long-term debt | (350 | ) | | — |
|
| Payment of preferred stock dividends | (1 | ) | | (1 | ) |
| Return of capital | — |
| | (110 | ) |
| Other financing activities | (1 | ) | | (1 | ) |
| Net cash provided from financing activities | 230 |
| | 656 |
|
| Net Change in Cash and Cash Equivalents | 79 |
| | 101 |
|
| Cash and Cash Equivalents at Beginning of Period | 133 |
| | 145 |
|
| Cash and Cash Equivalents at End of Period | $ | 212 |
| | $ | 246 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
| Interest (paid $39 and $37, net of $37 and $29 capitalized for 2015 and 2014, respectively) | $ | 2 |
| | $ | 8 |
|
| Income taxes, net | (181 | ) | | (34 | ) |
| Noncash transactions — | | | |
| Accrued property additions at end of period | 99 |
| | 136 |
|
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | 301 |
| | — |
|
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 June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 212 |
| | $ | 133 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 44 |
| | 43 |
|
| Unbilled revenues | | 37 |
| | 35 |
|
| Other accounts and notes receivable | | 11 |
| | 11 |
|
| Affiliated companies | | 43 |
| | 51 |
|
| Accumulated provision for uncollectible accounts | | (1 | ) | | (1 | ) |
| Fossil fuel stock, at average cost | | 95 |
| | 100 |
|
| Materials and supplies, at average cost | | 69 |
| | 62 |
|
| Other regulatory assets, current | | 69 |
| | 73 |
|
| Prepaid income taxes | | 193 |
| | 191 |
|
| Other current assets | | 7 |
| | 6 |
|
| Total current assets | | 779 |
| | 704 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,456 |
| | 4,378 |
|
| Less accumulated provision for depreciation | | 1,194 |
| | 1,173 |
|
| Plant in service, net of depreciation | | 3,262 |
| | 3,205 |
|
| Construction work in progress | | 2,543 |
| | 2,161 |
|
| Total property, plant, and equipment | | 5,805 |
| | 5,366 |
|
| Other Property and Investments | | 6 |
| | 5 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 260 |
| | 226 |
|
| Other regulatory assets, deferred | | 482 |
| | 385 |
|
| Income taxes receivable, non-current | | 544 |
| | — |
|
| Other deferred charges and assets | | 71 |
| | 71 |
|
| Total deferred charges and other assets | | 1,357 |
| | 682 |
|
| Total Assets | | $ | 7,947 |
| | $ | 6,757 |
|
|
| | | | | | | | | | | | | | | |
| | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) |
| Net Income | $ | 3 |
| | $ | 50 |
| | $ | 14 |
| | $ | 85 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 3 |
| | $ | 50 |
| | $ | 14 |
| | $ | 85 |
|
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
MISSISSIPPI POWER COMPANY
CONDENSED BALANCE SHEETSSTATEMENTS OF CASH FLOWS (UNAUDITED)
|
| | | | | | | | |
| Liabilities and Stockholder's Equity | | At June 30,
2015 | | At December 31,
2014 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 429 |
| | $ | 778 |
|
| Notes payable | | 505 |
| | — |
|
| Interest-bearing refundable deposits | | — |
| | 275 |
|
| Accounts payable — | | | | |
| Affiliated | | 88 |
| | 86 |
|
| Other | | 136 |
| | 178 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | — |
| | 142 |
|
| Other accrued taxes | | 47 |
| | 84 |
|
| Accrued interest | | 13 |
| | 76 |
|
| Accrued compensation | | 14 |
| | 26 |
|
| Over recovered regulatory clause liabilities | | 33 |
| | 1 |
|
| Mirror CWIP | | 353 |
| | 271 |
|
| Other current liabilities | | 59 |
| | 61 |
|
| Total current liabilities | | 1,677 |
| | 1,978 |
|
| Long-term Debt: | | | | |
| Long-term debt, affiliated | | 301 |
| | — |
|
| Long-term debt, non-affiliated | | 1,623 |
| | 1,630 |
|
| Total Long-term Debt | | 1,924 |
| | 1,630 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 844 |
| | 285 |
|
| Accumulated deferred investment tax credits | | 282 |
| | 283 |
|
| Employee benefit obligations | | 146 |
| | 148 |
|
| Asset retirement obligations | | 148 |
| | 48 |
|
| Other cost of removal obligations | | 170 |
| | 166 |
|
| Other regulatory liabilities, deferred | | 65 |
| | 64 |
|
| Other deferred credits and liabilities | | 410 |
| | 38 |
|
| Total deferred credits and other liabilities | | 2,065 |
| | 1,032 |
|
| Total Liabilities | | 5,666 |
| | 4,640 |
|
| 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 | | 2,692 |
| | 2,612 |
|
| Accumulated deficit | | (475 | ) | | (559 | ) |
| Accumulated other comprehensive loss | | (7 | ) | | (7 | ) |
| Total common stockholder's equity | | 2,248 |
| | 2,084 |
|
| Total Liabilities and Stockholder's Equity | | $ | 7,947 |
| | $ | 6,757 |
|
|
| | | | | | | |
| | For the Six Months Ended June 30, |
| | 2016 | | 2015 |
| | (in millions) |
| Operating Activities: | | | |
| Net income | $ | 14 |
| | $ | 85 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | |
| Depreciation and amortization, total | 82 |
| | 55 |
|
| Deferred income taxes | (16 | ) | | 694 |
|
| Investment tax credits | — |
| | 32 |
|
| Allowance for equity funds used during construction | (59 | ) | | (53 | ) |
| Regulatory assets associated with Kemper IGCC | (10 | ) | | (50 | ) |
| Estimated loss on Kemper IGCC | 134 |
| | 32 |
|
| Income taxes receivable, non-current | — |
| | (544 | ) |
| Other, net | 3 |
| | 8 |
|
| Changes in certain current assets and liabilities — | | | |
| -Receivables | 15 |
| | 6 |
|
| -Fossil fuel stock | 6 |
| | 5 |
|
| -Prepaid income taxes | 34 |
| | 24 |
|
| -Other current assets | (3 | ) | | (7 | ) |
| -Accounts payable | (12 | ) | | (25 | ) |
| -Accrued taxes | 19 |
| | (51 | ) |
| -Accrued interest | — |
| | (7 | ) |
| -Accrued compensation | (12 | ) | | (12 | ) |
| -Over recovered regulatory clause revenues | 4 |
| | 32 |
|
| -Mirror CWIP | — |
| | 82 |
|
| -Customer liability associated with Kemper refunds | (69 | ) | | — |
|
| -Other current liabilities | 7 |
| | 3 |
|
| Net cash provided from operating activities | 137 |
| | 309 |
|
| Investing Activities: | | | |
| Property additions | (403 | ) | | (428 | ) |
| Construction payables | (11 | ) | | (15 | ) |
| Capital grant proceeds | 137 |
| | — |
|
| Other investing activities | (19 | ) | | (17 | ) |
| Net cash used for investing activities | (296 | ) | | (460 | ) |
| Financing Activities: | | | |
| Increase in notes payable, net | — |
| | 475 |
|
| Proceeds — | | | |
| Capital contributions from parent company | 226 |
| | 77 |
|
| Long-term debt issuance to parent company | 200 |
| | — |
|
| Other long-term debt issuances | 900 |
| | — |
|
| Short-term borrowings | — |
| | 30 |
|
| Redemptions — | | | |
| Short-term borrowings | (475 | ) | | — |
|
| Long-term debt to parent company | (225 | ) | | — |
|
| Other long-term debt | (425 | ) | | (350 | ) |
| Other financing activities | (3 | ) | | (2 | ) |
| Net cash provided from financing activities | 198 |
| | 230 |
|
| Net Change in Cash and Cash Equivalents | 39 |
| | 79 |
|
| Cash and Cash Equivalents at Beginning of Period | 98 |
| | 133 |
|
| Cash and Cash Equivalents at End of Period | $ | 137 |
| | $ | 212 |
|
| Supplemental Cash Flow Information: | | | |
| Cash paid (received) during the period for — | | | |
Interest (paid $49 and $39, net of $23 and $37 capitalized for 2016
and 2015, respectively) | $ | 26 |
| | $ | 2 |
|
| Income taxes, net | (122 | ) | | (181 | ) |
| Noncash transactions — | | | |
| Accrued property additions at end of period | 94 |
| | 99 |
|
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest | — |
| | 301 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Assets: | | | | |
| Cash and cash equivalents | | $ | 137 |
| | $ | 98 |
|
| Receivables — | | | | |
| Customer accounts receivable | | 35 |
| | 26 |
|
| Unbilled revenues | | 46 |
| | 36 |
|
| Income taxes receivable, current | | — |
| | 20 |
|
| Other accounts and notes receivable | | 5 |
| | 10 |
|
| Affiliated companies | | 12 |
| | 20 |
|
| Fossil fuel stock, at average cost | | 99 |
| | 104 |
|
| Materials and supplies, at average cost | | 77 |
| | 75 |
|
| Other regulatory assets, current | | 97 |
| | 95 |
|
| Prepaid income taxes | | 5 |
| | 39 |
|
| Other current assets | | 7 |
| | 8 |
|
| Total current assets | | 520 |
| | 531 |
|
| Property, Plant, and Equipment: | | | | |
| In service | | 4,809 |
| | 4,886 |
|
| Less accumulated provision for depreciation | | 1,248 |
| | 1,262 |
|
| Plant in service, net of depreciation | | 3,561 |
| | 3,624 |
|
| Construction work in progress | | 2,429 |
| | 2,254 |
|
| Total property, plant, and equipment | | 5,990 |
| | 5,878 |
|
| Other Property and Investments | | 11 |
| | 11 |
|
| Deferred Charges and Other Assets: | | | | |
| Deferred charges related to income taxes | | 317 |
| | 290 |
|
| Other regulatory assets, deferred | | 520 |
| | 525 |
|
| Income taxes receivable, non-current | | 544 |
| | 544 |
|
| Other deferred charges and assets | | 85 |
| | 61 |
|
| Total deferred charges and other assets | | 1,466 |
| | 1,420 |
|
| Total Assets | | $ | 7,987 |
| | $ | 7,840 |
|
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 June 30, 2016 | | At December 31, 2015 |
| | | (in millions) |
| Current Liabilities: | | | | |
| Securities due within one year | | $ | 343 |
| | $ | 728 |
|
| Notes payable | | 25 |
| | 500 |
|
| Accounts payable — | | | | |
| Affiliated | | 87 |
| | 85 |
|
| Other | | 120 |
| | 135 |
|
| Customer deposits | | 16 |
| | 16 |
|
| Accrued taxes — | | | | |
| Accrued income taxes | | 57 |
| | — |
|
| Other accrued taxes | | 48 |
| | 85 |
|
| Accrued interest | | 19 |
| | 18 |
|
| Accrued compensation | | 14 |
| | 26 |
|
| Asset retirement obligations, current | | 21 |
| | 22 |
|
| Over recovered regulatory clause liabilities | | 100 |
| | 96 |
|
| Customer liability associated with Kemper refunds | | 5 |
| | 73 |
|
| Other current liabilities | | 41 |
| | 52 |
|
| Total current liabilities | | 896 |
| | 1,836 |
|
| Long-term Debt: | | | | |
| Long-term debt, affiliated | | 551 |
| | 576 |
|
| Long-term debt, non-affiliated | | 2,164 |
| | 1,310 |
|
| Total Long-term Debt | | 2,715 |
| | 1,886 |
|
| Deferred Credits and Other Liabilities: | | | | |
| Accumulated deferred income taxes | | 773 |
| | 762 |
|
| Deferred credits related to income taxes | | 8 |
| | 8 |
|
| Accumulated deferred investment tax credits | | 5 |
| | 5 |
|
| Employee benefit obligations | | 148 |
| | 153 |
|
| Asset retirement obligations, deferred | | 157 |
| | 154 |
|
| Unrecognized tax benefits | | 368 |
| | 368 |
|
| Other cost of removal obligations | | 169 |
| | 165 |
|
| Other regulatory liabilities, deferred | | 74 |
| | 71 |
|
| Other deferred credits and liabilities | | 40 |
| | 40 |
|
| Total deferred credits and other liabilities | | 1,742 |
| | 1,726 |
|
| Total Liabilities | | 5,353 |
| | 5,448 |
|
| 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 | | 3,122 |
| | 2,893 |
|
| Accumulated deficit | | (553 | ) | | (566 | ) |
| Accumulated other comprehensive loss | | (6 | ) | | (6 | ) |
| Total common stockholder's equity | | 2,601 |
| | 2,359 |
|
| Total Liabilities and Stockholder's Equity | | $ | 7,987 |
| | $ | 7,840 |
|
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
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electricity 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. 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. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.
In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE(Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when 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 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.
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 October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as 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 $6.23$6.68 billion, which includes approximately $4.96$5.43 billion of costs subject to the construction cost cap.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 of $23totaling $81 million ($1450 million after tax) in the second quarter 20152016 and $9a total of $134 million ($683 million after tax) infor the first quarter 2015.six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.08$2.55 billion ($1.281.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2015.
Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016. The current cost estimate includes costs through MarchOctober 31, 2016. As
In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a resultstipulation (the 2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. On July 27, 2016, the Mississippi Supreme Court (Court) dismissed Greenleaf CO2 Solutions, LLC’s (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the additional factorsIn-Service Asset Rate Order. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected to occur by October 31, 2016. The ultimate outcome of these matters cannot be determined at this time.
Southern Company and Mississippi Power are defendants in lawsuits that allege improper disclosure of important facts about the Kemper IGCC. One lawsuit was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean and seeks unspecified actual damages, punitive damages, and attorney's fees, costs, and interest. Another lawsuit was filed by Treetop Midstream Services, LLC (Treetop) and other related parties and seeks $100 million in compensatory damages, as well as punitive damages, costs, and interest. 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 potentialSEC 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 impact start-up2010 and operational readiness activities for this first-of-a-kind technology as described herein,on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the risk of further schedule extensions and/or cost increases, which could be material, remains.Kemper IGCC.
For additional information on the Kemper IGCC, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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"Integrated Coal Gasification Combined Cycle"Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein.
On February 12, 2015, the Mississippi Supreme Court (Court) issued its decision in a legal challenge with respect to the Mississippi PSC's March 2013 order that authorized the collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP. The Court reversed the 2013 MPSC Rate Order, deemed the 2013
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Settlement Agreement (defined below) between8, 2016, Mississippi Power borrowed $900 million under a new term loan agreement with a syndicate of financial institutions and used the Mississippi PSC unenforceable dueproceeds to a lack of public notice for the related proceedings, and directed the Mississippi PSC to enter an order requiringrepay $900 million in maturing bank loans. Mississippi Power has the right to refundborrow the Mirror CWIP amounts collected pursuant$300 million remaining under the agreement on or before October 15, 2016 and expects to the 2013 MPSC Rate Order. As ofuse those funds to repay senior notes maturing in October 2016. On June 30, 2015, $331 million had been collected by Mississippi Power. On March 12, 2015,27, 2016, Mississippi Power and the Mississippi PSC filed motions for rehearing, and, on June 11, 2015, the Court issued its final decision, rejecting both Mississippi Power's and the Mississippi PSC's motions for rehearing and requiring thatreceived a rate refund be made and that the Mirror CWIP rate be terminated. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a refund plan to the Mississippi PSC on July 21, 2015,$225 million capital contribution from Southern Company which proposed two alternative refund plans for the Mississippi PSC's consideration: (1) bill credit with check option; or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information.
Prior to the Court's final decision on June 11, 2015, Mississippi Power sought alternate rate recovery and filed a rate case on May 15, 2015 (2015 Rate Case). Mississippi Power's 2015 Rate Case presented the Mississippi PSC with three alternative rate proposals: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). RMP 2019 contemplated the total Mirror CWIP funds collected would bewas used to offset the retail revenue requirements over the life of the plan. However, in light of the Court's mandate and the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On May 20, 2015, SMEPA notified Mississippi Power of its termination of the asset purchase agreement (APA) between Mississippi Power and SMEPA whereby SMEPA previously agreed to purchase a 15% undivided interest in the Kemper IGCC. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
The return of approximately $301 million to SMEPA in June 2015 in connection with the termination of the APA, the required refund of the approximately $353 million of Mirror CWIP rate collections, including associated carrying costs, and the termination of the Mirror CWIP rates have adversely impacted Mississippi Power's ability to obtain financing needed for its business operations.
As a result, on July 10, 2015, Mississippi Power submitted a supplemental filing with the Mississippi PSC that includes a request for interim rates (Supplemental Notice) until such time as the Mississippi PSC renders a final decision on an additional alternative rate proposal (In-Service Asset Proposal). The Supplemental Notice was filed in response to the Mississippi PSC's July 7, 2015 order and presents the In-Service Asset Proposal for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016 and is 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 Supplemental Notice requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates under the In-Service Asset Proposal. Evidentiary hearings on the interim rate relief are scheduled to be held on August 6, 2015.
See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.
As of June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $898 million primarily due to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
costs through June 30, 2015. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information. In addition, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 millionrepay to Southern Company that matures on December 2, 2016 in conjunction with the repaymenta portion of SMEPA's deposits with interest, following the termination of SMEPA's planned purchase of 15% of the Kemper IGCC project. Furthermore, Mississippi Power expects to fund the cash component of the Mirror CWIP refund with an intercompany loan from Southern Company. 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.existing promissory note.
Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC. 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, Mississippi Power 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. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC and the Court's decision that have negatively impacted Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for 2015, as compared to the target.
RESULTS OF OPERATIONS
Net Income (Loss)
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(13) | | (21.0) | | $194 | | N/M |
N/M-Not meaningful |
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(47) | | (95.9) | | $(71) | | (84.5) |
Mississippi Power's net income after dividends on preferred stock for the second quarter 20152016 was $49$2 million compared to $62$49 million for the corresponding period in 2014.2015. The decrease was primarily related to higher pre-tax charges of $81 million ($50 million after tax) in the second quarter 2016 compared to pre-tax charges of $23 million in pre-tax charges ($14 million after tax) in the second quarter 2015 for revisions of the estimated costs expected to be incurred on
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 also due to a decrease in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in wholesale revenues, partially offset by an increase in retail revenues.
For year-to-date 2016, net income after dividends on preferred stock was $13 million compared to $84 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $134 million ($83 million after tax) in 2016 compared to pre-tax charges of $32 million ($20 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 also relateddue to a decrease in AFUDC equity, increasesinterest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in non-fuel operations and maintenance expenses, an increase inMay 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in retailwholesale revenues, primarily resulting from the Court's decision, partially offset by a decrease in interest expense.
For year-to-date 2015, net income after dividends on preferred stock was $84 million compared to a net loss of $110 million for the corresponding period in 2014. The increase was primarily related to $32 million in pre-tax charges ($20 million after tax) in 2015 compared to $380 million in pre-tax charges ($235 million after tax) in 2014 for revisions of 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 DOE Grants and excluding the Cost Cap Exceptions. The increase in net income was also related to a decrease in interest expense, partially offset by a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, an increase in depreciation and amortization, and a decrease in retail revenues primarily resulting from the Court's decision.revenues.
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
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cycle" and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information. Also see "Interest Expense, Net of Amounts Capitalized" herein for additional information.
Retail Revenues
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(22) | | (10.4) | | $(61) | | (14.6) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 9.0 | | $32 | | 9.0 |
In the second quarter 2015,2016, retail revenues were $189$206 million compared to $211$189 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, retail revenues were $357$389 million compared to $418$357 million for the corresponding period in 2014.2015.
Details of the changes in retail revenues were as follows:
| | | | | Second Quarter
2015 | | Year-to-Date 2015 | Second Quarter 2016 | | Year-to-Date 2016 |
| | | (in millions) |
| (% change) | | (in millions) | | (% change) | (in millions) | | (% change) | | (in millions) | | (% change) |
| Retail – prior year | | $ | 211 |
| | | | $ | 418 |
| | | $ | 189 |
| | | | $ | 357 |
| | |
| Estimated change resulting from – | | | | | | | | | | | | | | | |
| Rates and pricing | | (6 | ) | | (2.7 | ) | | (9 | ) | | (2.2 | ) | 32 |
| | 16.9 |
| | 57 |
| | 16.0 |
|
| Sales decline | | (1 | ) | | (0.6 | ) | | (5 | ) | | (1.2 | ) | |
| Sales growth (decline) | | (1 | ) | | (0.5 | ) | | 3 |
| | 0.8 |
|
| Weather | | 2 |
| | 0.9 |
| | 1 |
| | 0.2 |
| 1 |
| | 0.5 |
| | (2 | ) | | (0.6 | ) |
| Fuel and other cost recovery | | (17 | ) | | (8.0 | ) | | (48 | ) | | (11.4 | ) | (15 | ) | | (7.9 | ) | | (26 | ) | | (7.2 | ) |
| Retail – current year | | $ | 189 |
| | (10.4 | )% | | $ | 357 |
| | (14.6 | )% | $ | 206 |
| | 9.0 | % | | $ | 389 |
| | 9.0 | % |
Revenues associated with changes in rates and pricing decreasedincreased in the second quarter and year-to-date 20152016 when compared to the corresponding periods in 20142015, primarily due to $7 million and $11 million, respectively,the implementation of revenues associated with therates for certain Kemper IGCC cost recovery recognized in 2014, which ceased in 2015 as a result of the Court's decision, partially offset by $1 million in the second quarter 2015 and $2 million year-to-date 2015 in net revenues for the new energy efficiency cost recovery rate, which began in the fourth quarter 2014.
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" and "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Revenues attributable to changes in sales decreased in the second quarter 20152016 when compared to the corresponding period in 2014.2015. Weather-adjusted KWH sales to residential and commercial customers decreased 0.5%2.2% and 4.0%, respectively, in the second quarter 20152016 due to lowerdecreased customer usage, slightlypartially offset by an increase in customers. Weather-adjusted KWH sales to commercial customers increased 2.6% in the second quarter 2015 due to higher customer usage and an increase in customers. growth.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
KWH sales to industrial customers decreased 0.9%increased 2.9% in the second quarter 20152016 due to decreasedincreased usage by larger customers related to planned maintenance outages.customers.
Revenues attributable to changes in sales decreasedwere relatively flat for year-to-date 20152016 when compared to the corresponding period in 2014.2015. Weather-adjusted KWH energy sales to residential customers decreased 1.2% due to lower customer usage, slightly offset by an increase in customers. Weather-adjusted KWH energy sales to commercial customers decreased 0.2%1.9% due to lowerdecreased customer usage, slightlypartially offset by an increase in customers.customer growth. KWH energy sales to industrial customers increased 1.2% primarily dueand weather-adjusted KWH sales to increased usage by larger customers.residential customers were relatively flat.
In the first quarter 2015, Mississippi Power updated itsthe 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 secondfirst quarter
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
and year-to-date 2014 2015 KWH sales among customer classes that is consistent with the actual allocation in 2015.2016. Without these adjustments, second quarter 2015this adjustment, year-to-date 2016 weather-adjusted residential KWH sales increased 4.0%3.0%, weather-adjusted commercial KWH sales decreased 1.5%to commercial customers increased 1.6%, and industrial KWH sales decreased 2.1%to industrial customers increased 1.0% as compared to the corresponding period in 2014. Also, without these adjustments, year-to-date 2015 weather-adjusted residential KWH sales decreased 3.3%, weather-adjusted commercial KWH sales decreased 5.1%, and industrial KWH sales remained flat as compared to the corresponding period in 2014.2015.
Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 20152016 when compared to the corresponding periods in 2014,2015, primarily as a result of lower recoverable fuel costs. See "Fuel"Fuel and Purchased Power Expenses"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 – Non-Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(12) | | (16.0) | | $(31) | | (18.0) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(3) | | (4.8) | | $(21) | | (14.9) |
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 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 servesprovides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. 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.
In the second quarter 2015,2016, wholesale revenues from sales to non-affiliates were $63$60 million compared to $75$63 million for the corresponding period in 2014.2015. The decrease was primarily due to a $6 million decrease in energy revenues primarily resulting from lower fuel prices, partially offset by a $3 million increase in base and capacity revenues primarily resulting from a wholesale rate increase. For year-to-date 2015,2016, wholesale revenues from sales to non-affiliates were $141$120 million compared to $172$141 million for the corresponding period in 2014.2015. The decreases weredecrease was primarily due to a $14 million decrease in energy revenues primarily resulting from lower marketfuel prices and fuel cost.decreased usage and a $7 million decrease in base and capacity revenues primarily resulting from milder weather.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale Revenues – Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(2) | | (10.0) | | $2 | | 4.7 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(11) | | (61.1) | | $(29) | | (64.4) |
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 second quarter 2015,2016, wholesale revenues from sales to affiliates were $18$7 million compared to $20$18 million for the corresponding period in 2014.2015. The decrease was due to a $9 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $2 million decrease associated with lower natural gas prices.
For year-to-date 2016, wholesale revenues from sales to affiliates were $16 million compared to $45 million for the corresponding period in 2015. The decrease was due to a $23 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $6 million decrease associated with lower natural gas prices, partially offset by a $4 million increase in KWH sales due to higher gas generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014.
For year-to-date 2015, wholesale revenues from sales to affiliates were $45 million compared to $43 million for the corresponding period in 2014. The increase was due to an $18 million increase in KWH sales due to higher gas
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
generation partially as a result of the Kemper IGCC combined cycle being in service since August 2014, partially offset by a $16 million decrease associated with lower natural gas prices.
Fuel and Purchased Power Expenses
| | | | | Second Quarter 2015
vs.
Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 | | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) | | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (28 | ) | | (19.6) | | $ | (61 | ) | | (21.0 | ) | | $ | (34 | ) | | (29.6) | | $ | (72 | ) | | (31.4 | ) |
| Purchased power – non-affiliates | | 1 |
| | 100.0 | | (10 | ) | | (76.9 | ) | | (1 | ) | | (50.0) | | (2 | ) | | (66.7 | ) |
| Purchased power – affiliates | | (4 | ) | | (66.7) | | (11 | ) | | (73.3 | ) | | 2 |
| | 100.0 | | 5 |
| | 125.0 |
|
| Total fuel and purchased power expenses | | $ | (31 | ) | | $ | (82 | ) | | | | $ | (33 | ) | | $ | (69 | ) | | |
In the second quarter 2015,2016, total fuel and purchased power expenses were $119$86 million compared to $150$119 million for the corresponding period in 2014.2015. The decrease was due to a $28$16 million decrease in the volume of KWHs generated and purchased and a $17 million decrease in the average cost of fuel.
For year-to-date 2016, total fuel and purchased power andexpenses were $167 million compared to $236 million for the corresponding period in 2015. The decrease was due to a $3$34 million decrease in the volume of KWHs purchased.
For year-to-date 2015, total fuelgenerated and purchased power expenses were $236 million compared to $318 million for the corresponding period in 2014. The decrease was due toand a $72$35 million decrease in the average cost of fuel and purchased power and a $14 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.fuel.
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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | Second Quarter 2015 | | Second Quarter 2014 | | Year-to-Date 2015 | | Year-to-Date 2014 | Second Quarter 2016 | | Second Quarter 2015 | | Year-to-Date 2016 | | Year-to-Date 2015 |
Total generation (millions of KWHs)(*) | | 4,109 | | 3,932 | | 8,455 | | 7,974 | |
Total generation (millions of KWHs) | | 3,728 | | 4,109 | | 7,315 | | 8,455 |
Total purchased power (millions of KWHs) | | 114 | | 208 | | 227 | | 466 | 188 | | 114 | | 449 | | 227 |
Sources of generation (percent)(*) – | | | | |
Sources of generation (percent) – | | | |
| Coal | | 18 | | 47 | | 20 | | 46 | 5 | | 18 | | 8 | | 20 |
| Gas | | 82 | | 53 | | 80 | | 54 | 95 | | 82 | | 92 | | 80 |
Cost of fuel, generated (cents per net KWH) – | | |
| Coal | | 4.14 | | 4.18 | | 3.64 | | 4.21 | 5.49 | | 4.14 | | 4.16 | | 3.64 |
Gas(*) | | 2.71 | | 3.62 | | 2.69 | | 3.61 | |
Average cost of fuel, generated (cents per net KWH)(*) | | 2.98 | | 3.90 | | 2.90 | | 3.91 | |
Average cost of purchased power (cents per net KWH)(*) | | 3.19 | | 3.33 | | 3.37 | | 5.87 | |
| Gas | | 2.17 | | 2.71 | | 2.16 | | 2.69 |
Average cost of fuel, generated (cents per net KWH) | | 2.33 | | 2.98 | | 2.32 | | 2.90 |
Average cost of purchased power (cents per net KWH) | | 2.55 | | 3.19 | | 2.33 | | 3.37 |
| |
(*) | Includes energy produced during the test period for the Kemper IGCC which is accounted for in accordance with FERC guidance. |
Fuel
In the second quarter 2015,2016, fuel expense was $115$81 million compared to $143$115 million for the corresponding period in 2014.2015. The decrease was primarily due to a 23.6%10% decrease in the volume of KWHs generated, primarily as a result of milder weather, and a 22% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by2014. The decrease in volume included a 4.9%decrease in coal-fired generation of 76% and an increase in gas-fired generation of 5%.
For year-to-date 2016, total fuel expense was $157 million compared to $229 million for the corresponding period in 2015. The decrease was due to a 15% decrease in the volume of KWHs generated, resulting from the availabilityprimarily as a result of lower cost Mississippi Power units. The 4.9% increase in volume included an increase in gas-fired generation of 70.2%, partially offset bymilder weather, and a decrease in coal-fired generation of 60.2%.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
For year-to-date 2015, total fuel expense was $229 million compared to $290 million for the corresponding period in 2014. The decrease was primarily due to a 25.8%20% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in August 2014, at lower natural gas prices, partially offset by a 6.1% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units.2014. The 6.1% increasedecrease in volume also included an increase in gas-fired generation of 65.2%, offset by a 68% decrease in coal-fired generation of 53.7%.generation.
Purchased Power - Non-Affiliates
In the second quarter 2015, purchased power expense from non-affiliates was $2 million compared to $1 million for the corresponding period in 2014. The increase was primarily the result of a 57.6% increase in the average cost per KWH, offset by a 2.8% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014.
For year-to-date 2015, purchased power expense from non-affiliates was $3 million compared to $13 million for the corresponding period in 2014. The decrease was primarily the result of a 54.1% decrease in the volume of KWHs purchased due to an increase in Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014 and a 42.3% decrease in the average cost per KWH purchased as a result of lower natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.
Purchased Power - Affiliates
In the second quarter 2015, purchased power expense from affiliates was $2 million compared to $6 million for the corresponding period in 2014. The decrease was primarily due to a 58.3% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014, and a 24.7% decrease in the average cost per KWH purchased as a result of lower natural gas prices.
For year-to-date 2015, purchased power expense from affiliates was $4 million compared to $15 million for the corresponding period in 2014. The decrease was primarily due to a 50.0% decrease in the volume of KWHs purchased due to increased Mississippi Power generation partially as a result of the Kemper IGCC combined cycle being placed in service in August 2014, and a 41.5% decrease in the average cost per KWH purchased as a result of lower natural gas prices.
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, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $7 | | 11.5 | | $19 | | 15.2 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $(8) | | (5.6) |
In the second quarter 2015,For year-to-date 2016, other operations and maintenance expenses were $68$136 million compared to $61$144 million for the corresponding period in 2014.2015. The increasedecrease was primarily due to a $7$16 million decrease in generation outage costs, a $4 million decrease primarily related to pension costs, a $2 million decrease in transmission and distribution overhead line maintenance and vegetation management, and a $2 million decrease in uncollectibles expense and customer incentives. The decreases were partially offset by a $16 million increase in generation maintenance expenses primarily related to scheduled outages.the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began expensing in the third quarter 2015 in connection with the implementation of interim rates associated with the Kemper IGCC in-service assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification
For year-to-date 2015, other operations and maintenance expenses were $144 million compared to $125 million for the corresponding period in 2014. The increase was primarily due to a $6 million increase in generation
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
maintenance expenses including scheduled outages, a $5 million increase in employee compensationCombined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and benefits including pension," – Regulatory Assets and a $5 million increase related to uncollectible expenses and customer incentives.
Liabilities" herein for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $6 | | 25.0 | | $10 | | 21.3 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 50.0 | | $27 | | 47.4 |
In the second quarter 2015,2016, depreciation and amortization was $30$45 million compared to $24$30 million for the corresponding period in 2014. The increase was primarily due to a $2 million increase in depreciation related to increases in generation and distribution plant in service, a $2 million increase related to regulatory deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC, and a $1 million increase in ECO Plan amortization.
2015. For year-to-date 2015,2016, depreciation and amortization was $57$84 million compared to $47$57 million for the corresponding period in 2014. The increase was2015. These increases were primarily due to a $4 million increase in depreciation related to increases in generation, transmissionadditional amortization expenses and distribution plant in service, a $4 million increase related to regulatorylower deferrals associated with Plant Daniel Units 3 and 4 and the Kemper IGCC combined cycle assets of $13 million and a$22 million in the second quarter and year-to-date 2016, respectively, in accordance with the In-Service Asset Rate Order. Additionally, increases of $2 million increaseand $5 million in ECO Plan amortization.the second quarter and year-to-date 2016, respectively, are related to additional plant in service.
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. SeeAlso, 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 Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information.
Taxes Other Than Income Taxes
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $3 | | 15.0 | | $7 | | 17.1 |
In the second quarter 2015, taxes other than income taxes were $23 million compared to $20 million for the corresponding period in 2014. The increase was primarily due to a $3 million increase in ad valorem taxes, partially offset by a $1 million decrease in franchise tax.
For year-to-date 2015, taxes other than income taxes were $48 million compared to $41 million for the corresponding period in 2014. The increase was primarily due to a $9 million increase in ad valorem taxes, partially offset by a $2 million decrease in franchise taxes.
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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $23 | | N/M | | $(348) | | (91.6) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $58 | | N/M | | $102 | | N/M |
N/M-NotM - Not meaningful
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarterquarters of 2016 and 2015, an estimated probable loss on the Kemper IGCC of $23 million was recorded at Mississippi Power. For year-to-date 2015 and year-to-date 2014, estimated probable losses on the Kemper IGCC of $32$81 million and $380$23 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 $134 million and $32 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"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Allowance for Equity Funds Used During Construction
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(12) | | (32.4) | | $(22) | | (29.3) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $5 | | 20.0 | | $6 | | 11.3 |
In the second quarter 2015,of 2016, AFUDC equity was $25$30 million compared to $37$25 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, AFUDC equity was $53$59 million compared to $75$53 million for the corresponding period in 2014.2015. The decreases areincrease was driven by a reductionhigher AFUDC equity rate and an increase in Kemper IGCC AFUDC, primarily associated with the AFUDCwholesale settlement agreement removing all Kemper IGCC CWIP from rate andbase, partially offset by placing the combined cycle and the associated common facilities portion of the Kemper IGCCPlant Daniel scrubbers in service in August 2014. November 2015. See Note 3 to the
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $45 | | N/M | | $50 | | N/M |
N/M - Not meaningful
In the second quarter 2016, interest expense, net of amounts capitalized was $15 million compared to $(30) million for the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $31 million compared to $(19) million for the corresponding period in 2015. The increases were primarily due to a $38 million and a $31 million decrease for the second quarter and year-to-date 2016, respectively, in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. In addition, these increases were related to additional long-term debt and decreases in amounts capitalized, partially offset by a decrease in interest on Mirror CWIP.
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"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information regarding the Kemper IGCC.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(43) | | N/M | | $(44) | | N/M |
N/M-Not meaningful
In the second quarter 2015, interest expense, net of amounts capitalized was ($30) million compared to $13 million for the corresponding period in 2014. For year-to-date 2015, interest expense, net of amounts capitalized was ($19) million compared to $25 million for the corresponding period in 2014. The decreases were primarily due to a $41 million decrease related to the termination of the APA between Mississippi Power and SMEPA which required the return of SMEPA's deposits at a lower rate of interest than accrued. Also contributing to the decrease was an increase in capitalized interest primarily resulting from carrying costs related to the Kemper IGCC. 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 Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.
Income Taxes (Benefit)
|
| | | | | | |
Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
(change in millions) |
| (% change) | | (change in millions) | | (% change) |
$— | | — | | $134 | | N/M |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(33) | | N/M | | $(47) | | N/M |
N/M-NotM - Not meaningful
In the second quarter 2015 and 2014,2016, income taxes were $16 million. For year-to-date 2015, income taxes (benefit) were $20tax benefit was $(17) million compared to $(114)an expense of $16 million for the corresponding period in 2014.2015. For year-to-date 2016, income tax benefit was $(27) million compared to an expense of $20 million for the corresponding period in 2015. The changechanges were primarily reflects a
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
due to the reduction in tax benefitspre-tax earnings related to the estimated probable losses on the construction of the Kemper IGCC recorded in 2014.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. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs, its ability to recover costs in a timely manner,prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC andin accordance with any operational parameters that may be adopted by the Plant Daniel scrubber projectMississippi PSC, as well as other ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of 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. ChangesDemand 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, may impact sales for Mississippi Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth andwhich may impact future earnings. For additional information relating to these issues, see RISK
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. 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.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.
On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal. As of June 30, 2015, Mississippi Power reclassified the net carrying value of these assets from accumulated provision for depreciation to other regulatory assets, deferred, in accordance with an accounting order from the Mississippi PSC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Sierra Club Settlement Agreement" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.
Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.
New Source Review Actions
See Note 3 to the financial statements of Mississippi Power under "Environmental Matters – New Source Review Actions" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case. If approved by the U.S. District Court for the Northern District of Alabama, Alabama
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of this matter cannot be determined at this time.
Environmental Statutes and Regulations
See Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters –Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM), the final MATS rule and the Cross State Air Pollution Rule (CSAPR).regional haze regulations.
On April 25, 2016, in response to a June 12, 2015 U.S. Supreme Court opinion, the EPA published a finalits supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule requiring affected states (including Alabamacompliance requirements, costs, or deadlines, and Mississippi)all Mississippi Power units that are subject to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSMthe MATS rule have completed the measures necessary to achieve compliance with the MATS rule by no later than November 22, 2016.the applicable deadlines.
Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the final ruleproposed revisions will depend on the outcome oftheir ultimate adoption, implementation, and any legal challenges and the development and approval of SIPs by the affected states and cannot be determined at this time.
On June 29, 2015, the U.S. Supreme Court issued a decision finding that the EPA had failed to properly consider costs in its decision to regulate hazardous air pollutant emissions from electric generating units under the MATS rule and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. The MATS rule remains in effect while the U.S. Court of Appeals for the District of Columbia Circuit and the EPA respond to the decision. The ultimate impact of this decision cannot be determined at this time.
On July 28, 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion invalidating certain emissions budgets under the CSAPR Phase II emissions trading program for a number of states, including Alabama. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule. The ultimate impact of this decision will depend on additional rulemaking and cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's and the U.S. Army Corps of Engineers' proposed rule revising the definition of waters of the U.S. under the Clean Water Act (CWA).
On June 29, 2015, the EPA and the U.S. Army Corps of Engineers jointly published a final rule revising the regulatory definition of waters of the U.S. for all CWA programs. The final rule significantly expands the scope of federal jurisdiction under the CWA and could have significant impacts on economic development projects which could affect customer demand growth. In addition, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. The rule becomes effective August 28, 2015. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the EPA's and the U.S. Army Corps of Engineers' field-level implementation of the rule and cannot be determined at this time.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Mississippi Power recorded incremental asset retirement obligations (ARO) of approximately $95 million related to the CCR Rule in the second quarter 2015. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. See Note (A) to the Condensed Financial Statements herein for additional information regarding Mississippi Power's AROs.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed regulation of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. One of the final rules contains specific emission standards governing CO2 emissions from new, modified, and reconstructed units. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Mississippi Power's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates or through market-based contracts. However, the ultimate financial and operational impact of the final rules on Mississippi Power cannot be determined at this time and will depend on numerous factors including the Southern Company system's ongoing review of the final rules; the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challenges and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.
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) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
On March 31, 2015,2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgofor an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, accepted by the FERC, effective for services rendered beginning May 1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. The increase reflectedis primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. 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 36 months, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
expense, and (iv) removing all of the filing by, among other things, increasing theKemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, which was accepted by the FERC on May 13, 2015, provides that the additional accrual of AFUDC was effective April 1, 2015.AFUDC. The additional resulting AFUDC is projectedestimated to be approximately $11 million annually, of which $8 million relates tothrough the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a resultIGCC's projected in-service date of a portion of the Kemper IGCC being placed in service prior to the projected date. The MarchOctober 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.
Market-Based Rate Authority
Mississippi Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies (including Mississippi Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Mississippi Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional operating companies (including Mississippi Power) 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 operating companies (including Mississippi Power) and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.2016.
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 the Kemper IGCC, fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are 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"Retail Regulatory Matters"Matters – Mississippi Power" and "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Renewables
In April and MayNovember 2015, the Mississippi Power entered into separate PPAs forPSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power wouldwill purchase all of the energy produced by the solar facilities for the 25-year term under each of the contracts. If approved by the Mississippi PSC, thethree PPAs. The projects are expected to be in service by the end of 2016second quarter 2017 and the resulting energy purchases willare expected to be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcomeMississippi Power may retire the renewable energy credits (REC) generated on behalf of this matter cannot be determined at this time.its customers or sell the RECs, separately or bundled with energy, to third parties.
Energy Efficiency
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
On March 17, 2015,April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2014,2015, 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 surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. change in rates.
The ultimate outcome of this matterthese matters cannot be determined at this time.
Fuel Cost Recovery
118
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Ad Valorem Tax Adjustment
On April 23, 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 of February. As required by the order, on February 1, 2016, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily duesubmitted updated natural gas price forecasts and resulting fuel factors to a decrease in average millage rates. On May 26, 2015,the Mississippi PSC. If approved by the Mississippi PSC, suspended the filing to allow it more time to review.updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.
Integrated Coal Gasification Combined Cycle
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Kemper IGCC Overview
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. 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 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 using natural gas in August 2014 and continues to focus onprogress towards completing the remainder of the Kemper IGCC, including the gasifiergasifiers and the gas clean-up facilities,facilities. The in-service date for which the in-service dateremainder of the Kemper IGCC is currently expected to occur inby October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the first halfrelated lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of 2016. the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with 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 Court decision)Court's decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision,2016, are as follows:
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| | | Cost Category | 2010 Project Estimate(f) | | Current Estimate | | Actual Costs at June 30, 2015 | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(a)(e) | $ | 2.40 |
| | $ | 4.96 |
| | $ | 4.51 |
| $ | 2.40 |
| | $ | 5.43 |
| | $ | 5.15 |
|
| 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 |
| | 0.11 |
| | 0.12 |
|
AFUDC(c)(d) | 0.17 | | 0.62 | | 0.52 | 0.17 |
| | 0.72 |
| | 0.66 |
|
Combined Cycle and Related Assets Placed in Service – Incremental(d) | — |
| | 0.02 |
| | — |
| |
Combined Cycle and Related Assets Placed in
Service – Incremental(e) | | — |
| | 0.03 |
| | 0.02 |
|
| General Exceptions | 0.05 | | 0.10 | | 0.08 | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(c)(e) | — |
| | 0.19 | | 0.15 | |
Total Kemper IGCC(a)(c) | $ | 2.97 |
| | $ | 6.23 |
| | $ | 5.60 |
| |
Deferred Costs(e) | | — |
| | 0.20 |
| | 0.19 |
|
| Additional DOE Grants | | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | | $ | 2.97 |
| | $ | 6.68 |
| | $ | 6.32 |
|
| |
| (a) | (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 reflect estimated costs through October 31, 2016. |
| |
| (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"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"Order" herein for additional information. The Current Cost Estimate and the Actual Costs includereflect 100% of the 15% undivided interest incosts of the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.IGCC. See note (e) for additional information. |
| |
(b)(d) | Mississippi Power's original estimate2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs.Costs – 2013 MPSC Rate Order." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related toCurrent 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. |
| |
(c)(e) | AmountsNon-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 reflect estimatedand the Actual Costs at June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through March 31,income, are not included in the Current Cost Estimate and the Actual Costs at June 30, 2016. |
| |
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. |
| |
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." |
| |
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimateLiabilities" herein for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.
additional information. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.422016, $3.59 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 $2.08$2.55 billion), $2$6 million in other property and investments, $58$81 million in fossil fuel stock, $41$46 million in materials and supplies, $198$35 million in other regulatory assets, $16current, $180 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets and $24 million in AROs in the balance sheet, with $1 million previously expensed.sheet.
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. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23$81 million ($14($50 million after tax) in the second quarter 20152016 and $9a total of $134 million ($683 million after tax) for the six months ended June 30, 2016. Since 2012, in the first quarter 2015. These amounts are in addition toaggregate, Mississippi Power has incurred charges totaling $868 million ($536 million after tax), $1.10of $2.55 billion ($681 million after tax), and $78 million ($48 million1.57 billion after tax) as a result of changes in 2014, 2013, and 2012, respectively.the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increasesincrease to the cost estimate in the first and second quarters of 20152016 primarily reflectedreflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to equipment rework, scopeoperational readiness and challenges in
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016.refractory lining for the gasifiers. Any further extension of the in-service date beyond October 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 million per month, whichwhich 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 further extension of the in-service date with respect to the Kemper IGCC beyond October 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13$14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees which are being deferred as regulatory assets and are estimated to totalof approximately $7$3 million per month. For additional information, see "2015 Rate Case" herein.
Any furtherMississippi 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. Further cost increases and/or extensions of the expected in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality ofdifficulties integrating the systems required for sustained operations, major equipment materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, failure, unforeseen engineering or design problems start-up activities for this first-of-a-kind technology (including major equipment failure and system integration),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 subsequent periods, anyAny further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operationsincome 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 recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) to 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 be determined at this time, but 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 based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternativefuture 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.
2013 Settlement AgreementMPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that among other things, establishedwas 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-incurredprudently-
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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. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
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's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the
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estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, inIn 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. 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 the in-service date.IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.
In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a2015 and required the fourth quarter 2015 refund plan toof the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for$342 million collected under the Mississippi PSC's consideration: (1) bill credit2013 MPSC Rate Order, along with check option;associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.February 2013 legislation described below.
2015 Rate Case
As a result of theOn August 13, 2015, Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On
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May 15, 2015, Mississippi Power filed the 2015 Rate Case with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized by Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a Supplemental Notice with the Mississippi PSC in response to the July 7, 2015 order of theapproved Mississippi PSC. The Supplemental Notice presentsPower's request for interim rates, which presented an additional alternative rate proposal In-Service(In-Service Asset Proposal, for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, isProposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and iscosts. The interim rates were designed to collect approximately $159 million annually. The Supplemental Notice requests thatannually and became effective with the first billing cycle in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time asRate Order adopting in full the 2015 Stipulation entered into between Mississippi PSC renders a final decision onPower and the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates underMPUS regarding the In-Service Asset Proposal. Evidentiary hearingsThe In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the interim rate relief are scheduled to be heldMississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on August 6, 2015.
common equity, and actual embedded interest costs. The revenue requirements set forthIn-Service Asset Rate Order also included a prudence finding of all costs in the alternative rate proposals excludestipulated 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. See "Termination of Proposed Sale of Undivided InterestMississippi Power continues to SMEPA" herein for additional information.evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 daysWith implementation of the Supplemental Noticenew 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.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to put onerequest recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
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 three viable alternative rate proposals into effect as temporary rates under bondcertificated cost estimate of $2.4
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billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and subjectaccrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to refund pursuant to Mississippi state law.utilize alternate financing through securitization or the February 2013 legislation.
Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 20152016 of $6.23$6.68 billion, Mississippi Power anticipates that it will incur additional costs afterexpenses in excess of current rates associated with operating the Kemper IGCC in-service dateafter it is placed in service until the Kemper IGCC cost recovery approach is finalized.finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues andcosts. Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expectswill seek approval from the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not requireddefer these costs for
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interim future rate reliefrecovery to be granted.determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "2015 Mississippi Supreme Court Decision""Regulatory Assets and "2015 Rate Case" hereinLiabilities" below 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 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 June 30, 2015,2016, the regulatory asset balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million.totaled $101 million as of June 30, 2016. The amortization period for any such costs approved for recovery remains subjectthese assets is expected to approvalbe determined by the Mississippi PSC.PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
See "2015 Mississippi Supreme Court Decision""2013 MPSC Rate Order" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.
See Note 1 to the financial statements of Mississippi Power under "Regulatory"Regulatory Assets and Liabilities"Liabilities" in Item 8 of the Form 10-K for additional information.
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 June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 million. See "2015 Rate Case" herein for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own 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.
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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 has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC, (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury willwould purchase 70% of the CO2 captured from the Kemper IGCC and Treetop willwould purchase 30% of the CO2 captured from the Kemper IGCC. The agreementsOn 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 Treetop provide termination rights asif Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015,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 has been engaged in ongoing discussions with its off-takers regarding the status ofis not able to enter into other similar contractual arrangements or otherwise sequester the CO2 delivery schedule as well as other issues related to the respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Any termination or material modification of these agreementsproduced. Additionally, sustained oil price reductions could result in a material reduction in future chemical product salessignificantly lower revenues andthan Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial impactstatements.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, 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 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.
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.
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on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.
The ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
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 for additional information.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits "–Section 174 Research and Experimental Deduction" respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.
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 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.
TableThe SEC is conducting a formal investigation of ContentsSouthern 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.MISSISSIPPI POWER COMPANY
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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, and AFUDC.
Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery
During 2015,2016, 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
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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 of $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 incurred charges of $2.08$2.55 billion ($1.281.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2015.2016.
Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operationsincome and these changes could be material. Any furtherFurther cost increases and/or extensions of the expected in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality ofdifficulties integrating the systems required for sustained operations, major equipment materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, failure, unforeseen engineering or design problems start-up activities for this first-of-a-kind technology (including major equipment failure and system integration),including any repairs and/or modifications to systems, and/or operational performance (including but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).
Mississippi Power's revised cost estimate includes costs through MarchOctober 31, 2016. Any further extension of the in-service date beyond October 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$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 further extension of the in-service date with respect to the Kemper IGCC beyond October 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13$14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to totalof approximately $7$3 million per month.
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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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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 Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information.
Asset Retirement Obligations
AROs are computed as the fair value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.
The liability for AROs primarily relates to facilities that are subject to the CCR Rule, primarily ash ponds. In addition, Mississippi Power has retirement obligations related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
On April 17, 2015, the EPA published the final CCR Rule in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Mississippi Power recorded new AROs for facilities that are subject to the CCR Rule. The cost estimates are based on information that was known as of June 30, 2015 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements. As further analysis is performed, including evaluation of the expected timing and method of compliance and refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, Mississippi Power expects to periodically update these estimates. Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.
See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On April 7, 2015,February 25, 2016, the FASB issued Accounting Standards Update (ASU)ASU No. 2015-03,2016-02, Interest – Imputation of Interest (Subtopic 835-30):Leases Simplifying the Presentation of Debt Issuance Costs(Topic 842) (ASU 2016-02). The ASU 2016-02 requires that debt issuance costs relatedlessees to a recognized debt liability be presented inrecognize on the balance sheet as a direct deduction from the carrying amount of that debtlease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Mississippi Power is currently reflects unamortized debt issuance costs in other deferred chargesevaluating the new standard and assetshas not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on itsMississippi Power's balance sheet.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
balance sheet. UponOn 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. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Mississippi Power intends to adopt the reclassification willASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.
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"Integrated Coal Gasification Combined Cycle"Cycle" herein for additional information. Mississippi Power's financial condition was adversely affected by the return of approximately $301 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections, which as of June 30, 2015 was approximately $353 million including associated carrying costs, and the termination of the Mirror CWIP rate will further adversely impact Mississippi Power's financial condition and its ability to obtain financing needed for normal business operations and completion of the Kemper IGCC. Earnings for the six months ended June 30, 20152016 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order. Earnings for the six months endedIGCC.
Through June 30, 2014 were negatively affected by revisions2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.28 billion and is expected to incur approximately $0.27 billion in additional non-recoverable cash expenditures through completion of the cost estimate forconstruction and start-up of the Kemper IGCC.
In addition to funding normal business operations and projected capital expenditures, Mississippi Power's cash requirements primarily consist of $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs. In addition, Mississippi Power issued an 18-month promissory note to Southern Company in the aggregate principal amount of approximately $301 million related to the refund to SMEPA and expects to enter into a similar promissory note with Southern Company to fund the Mirror CWIP refund. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA," "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order,"" – 2015 Mississippi Supreme Court Decision," and " – 2015 Rate Case" herein for additional information. For the three-year period from 20152016 through 2017,2018, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental equipment formodifications to existing generating units, including the Plant Daniel scrubber project, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.
Through June 30, 2015,On January 28, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $1.62 billion and is expectedissued a promissory note for up to incur approximately $0.46 billion$275 million to Southern Company, which matures in additional non-recoverable cash expenditures through completion of the Kemper IGCC.
December 2017, bearing interest based on one-month LIBOR. During the first six months of 2015,2016, Mississippi Power received $75 million in equity contributionsborrowed from Southern Company. In April 2015,Company $100 million under this promissory note and an additional $100 million under a separate promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into two floating rate bank loansan unsecured term loan agreement with a maturity datesyndicate of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loansfinancial institutions for an aggregate principal amount of $425$1.2 billion. Mississippi Power borrowed $900 million which, among other things, extendedunder the maturity dates from various dates in 2015term loan agreement and has the right to April 1,borrow the remaining $300 million on or before October 15, 2016. On June 3, 2015,27, 2016, Mississippi Power issued an 18-month promissory note inreceived a capital contribution from Southern Company for $225 million, the aggregate principal amountproceeds of approximately $301 millionwhich were used to repay to Southern Company as a resultportion of the existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company's refundCompany totaled $551 million.
As of June 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $301$376 million primarily due to $300 million in depositssenior notes scheduled to mature on October 15, 2016, $40 million of variable rate pollution control revenue bonds backed by short-term credit facilities, and associated interest to SMEPA$25 million in connection with the termination of the APA.short-term debt. Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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-termthe remainder of its capital needs. See "Capital"Capital Requirements and Contractual Obligations," "Sources"Sources of Capital," and "Financing Activities""Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $137 million for the first six months of 2016, a decrease of $172 million as compared to the corresponding period in 2015. The decrease in cash provided from operating activities is primarily due to lower research and experimental (R&E) tax deductions and the cessation of Mirror CWIP collections and subsequent refund payments, partially offset by income taxes receivable associated with R&E deductions and accrued taxes. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net cash provided from operating activities totaled $309 million for the first six monthsGasification Combined Cycle – Rate Recovery of 2015, an increase of $131 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductionsKemper IGCC Costs" and bonus depreciation reducing tax payments, an increase in fuel recovery,"Unrecognized Tax Benefits – Section 174 Research and a decrease in receivables, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial StatementsExperimental Deduction" herein for additional information. Net cash used for investing activities totaled $460$296 million for the first six months of 20152016 primarily due to receipt of $137 million in Additional DOE Grants for the Kemper IGCC and gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project.IGCC. Net cash provided from financing activities totaled $230$198 million for the first six months of 20152016 primarily due to short-term bank loans,long-term debt issuances and capital contributions from Southern Company, and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flowdebt and 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 six months of 20152016 include an increase in long-term debt of $829 million. A portion of this debt was used to repay securities and notes payable resulting in a $385 million decrease in securities due within one year of $349and a $475 million decrease in notes payable. Additionally, CWIP increased $175 million primarily due to refinancing or replacing maturing long-term debt with short-term loans. Additionally, long-term debt increased $301 million and interest-bearing refundable deposit decreased $275 million, due to an intercompany loan for repayment of the SMEPA deposits and interest. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $439 million; other regulatory assets, deferred increased $97 million;Kemper IGCC and the Mirror CWIP regulatorycustomer liability increased $82 million primarily associated with construction, operation, and collections related to the Kemper IGCC. See – "Integrated Coal Gasification Combined Cycle" herein for additional information. Income taxes receivable, non-current; accrued income taxes; accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and other deferred credits and liabilities increased primarily due to R&E tax deductions and the related reserve. Additional changes include increases in notes payable primarily due to new short-term bank loans and asset retirement obligations due to the CCR Rule.IGCC refunds decreased $68 million. Total common stockholder's equity increased $164$242 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income duringfor the second quarter 2015.period.
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 $900$300 million will be required through June 30, 20162017 to fund maturities of bank term loans scheduled to mature on April 1, 2016long-term debt, and $30$25 million in short-term debt. In addition, Mississippi Power will be required to refund its Mirror CWIP rate collectionsfund maturities of approximately $353 million asshort-term debt. See "Sources of June 30, 2015, including associated carrying costs. See "Sources of Capital"Capital" herein for additional information.
The construction program of Mississippi Power is currently estimated to be $1.0 billion in 2015, $354 million in 2016, and $229$920 million for 2016, $218 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $801 million in 2015 and $150$745 million in 2016.
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. See Note (B) to the Condensed Financial Statements under "Integrated"Integrated Coal
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate"Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.
Sources of Capital
Except as described herein,In December 2015, the Mississippi Power plans to obtainPSC approved the funds requiredIn-Service Asset Rate Order, which among other things, provided for construction and other purposes from operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company. Mississippi Power's financial condition was adversely affected by the issuanceretail rate recovery of an 18-month promissory note to Southern Company related to the returnannual revenue requirement of approximately $301$126 million of interest bearing refundable deposits to SMEPA in June 2015 in connection with the termination of the APA. In addition, the required refund of Mirror CWIP rate collections of approximately $353 million as of June 30, 2015, including associated carrying costs, and the termination of the Mirror CWIP rate have further adversely impacted Mississippi Power's financial condition and its ability to obtain funds needed for normal business operations and completion of the Kemper IGCC.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 Mississippi Supreme Court Decision"Rate Case" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 Grants is expected to be received for commercial operation of the Kemper IGCC. On 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, 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 legislation related to the securitization of certain costs of the Kemper IGCC.
In April 2015,On January 28, 2016, Mississippi Power entered into two floating rate bank loans withissued a maturity date of April 1, 2016,promissory note for up to $275 million to Southern Company, which matures in an aggregate principal amount of $475 million,December 2017, bearing interest based on one-month LIBOR. The proceedsDuring the first six months of these loans were used for2016, Mississippi Power borrowed from Southern Company $100 million pursuant to the repayment of term loans in an aggregate principal amount of $275 million working capital,promissory note with a $50 million draw occurring on each of January 29, 2016 and other general corporate purposes.March 14, 2016, and an additional $100 million under a separate promissory note issued in November 2015. On March 8, 2016, Mississippi Power also amended three outstanding floating rate bank loansentered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate principal amount of $425$1.2 billion. Mississippi Power borrowed $900 million which, among other things, extendedunder the maturity dates from various datesterm loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in 2015maturing bank loans on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2016.2018 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 June 30, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $898 million primarily due2016, the amount of outstanding promissory notes to $900 million of bank term loans scheduled to mature on April 1, 2016, $30 million of short-term debt, and the required refund of approximately $353 million in Mirror CWIP, which includes associated carrying costs through June 30, 2015. Southern Company totaled $551 million.
Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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 June 30, 2015,2016, Mississippi Power had approximately $212$137 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 20152016 were as follows:
| | | Expires | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Due Within One Year |
| 2015 | | 2016 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | |
| 2016 | | 2016 | | 2017 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) |
| $ | 40 |
| | $ | 255 |
| | $ | 295 |
| | $ | 265 |
| | $ | 30 |
| | $ | 40 |
| | $ | 70 |
| | $ | 225 |
| 115 |
| | $ | 60 |
| | $ | 175 |
| | $ | 150 |
| | $ | — |
| | $ | 15 |
| | $ | 15 |
| | $ | 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"Bank Credit Arrangements"Arrangements" herein for additional information.
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
A portion of the $265 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2015 was approximately $40 million.
Most of these bank credit arrangements, as well as Mississippi Power's term loan arrangements, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness (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 specifiedspecific 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. Mississippi Power is currently 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 seek to extend the maturity dates and/or increase or decrease the lending commitments thereunder.
To
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
A portion of the extent available,$150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power may seek to utilize a Southern Company subsidiary organized to issuePower's pollution control revenue bonds and sell commercial paper at the request and for the benefitborrowings. The amount of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefitvariable rate pollution control revenue bonds outstanding requiring liquidity support as of Mississippi Power would be loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.June 30, 2016 was approximately $40 million.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 30, 2015 | | Short-term Debt During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| Short-term bank debt | | $ | 505 |
| | 1.4% | | $ | 460 |
| | 1.4% | | $ | 505 |
|
|
| | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 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 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2015.2016. |
Credit Rating Risk
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-BBB and/or Baa3Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.management, and transmission. At June 30, 2015,2016, 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 $282$251 million.
Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, anya credit rating downgrade has impacted and may continue tocould impact the ability of Mississippi Power's abilityPower to access capital markets, particularlyand would be likely to impact the short-term debt market and the variable rate pollution control revenue bond market.cost at which it does so.
On June 5, 2015,May 12, 2016, Fitch downgraded the senior unsecured long-term issuer defaultdebt rating of Mississippi Power to BBB+ from A-. Fitch maintainedA- and revised the negative ratings outlook forfrom negative to stable.
Financing Activities
In January 2016, Mississippi Power.
Subsequent issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of June 30, 2015, S&P placed its ratings2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. 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 existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
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 to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the traditional operating companies (includingterm loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power)Power used the initial proceeds to repay $900 million in maturing bank notes on CreditWatch with negative implications.March 8, 2016 and
MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financing Activitiesexpects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.
In March 2015,June 2016, Mississippi Power repaid at maturityrenewed a $75$10 million bank term loan.
In April 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million,short-term note, which matures on June 30, 2017, bearing interest based on one-monththree-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015, Mississippi Power issued an 18-month floating rate promissory note to Southern Company bearing interest based on one-month LIBOR. This note was for an aggregate principal amount of approximately $301 million, the amount paid by Southern Company to SMEPA pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.
SOUTHERN POWER COMPANY
AND SUBSIDIARY COMPANIES
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
| | | | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Operating Revenues: | | | | | | | | | | | | | | |
| Wholesale revenues, non-affiliates | $ | 250 |
| | $ | 260 |
| | $ | 481 |
| | $ | 538 |
| $ | 264 |
| | $ | 250 |
| | $ | 480 |
| | $ | 481 |
|
| Wholesale revenues, affiliates | 85 |
| | 68 |
| | 199 |
| | 140 |
| 107 |
| | 85 |
| | 204 |
| | 199 |
|
| Other revenues | 2 |
| | 1 |
| | 4 |
| | 2 |
| 2 |
| | 2 |
| | 4 |
| | 4 |
|
| Total operating revenues | 337 |
| | 329 |
| | 684 |
| | 680 |
| 373 |
| | 337 |
| | 688 |
| | 684 |
|
| Operating Expenses: | | | | | | | | | | | | | | |
| Fuel | 105 |
| | 118 |
| | 243 |
| | 243 |
| 96 |
| | 105 |
| | 187 |
| | 243 |
|
| Purchased power, non-affiliates | 18 |
| | 17 |
| | 34 |
| | 45 |
| 21 |
| | 18 |
| | 35 |
| | 34 |
|
| Purchased power, affiliates | 4 |
| | 16 |
| | 14 |
| | 46 |
| 2 |
| | 4 |
| | 8 |
| | 14 |
|
| Other operations and maintenance | 69 |
| | 69 |
| | 121 |
| | 122 |
| 86 |
| | 69 |
| | 162 |
| | 121 |
|
| Depreciation and amortization | 60 |
| | 52 |
| | 118 |
| | 103 |
| 81 |
| | 60 |
| | 154 |
| | 118 |
|
| Taxes other than income taxes | 6 |
| | 6 |
| | 12 |
| | 11 |
| 6 |
| | 6 |
| | 13 |
| | 12 |
|
| Total operating expenses | 262 |
|
| 278 |
| | 542 |
| | 570 |
| 292 |
|
| 262 |
| | 559 |
| | 542 |
|
| Operating Income | 75 |
| | 51 |
| | 142 |
| | 110 |
| 81 |
| | 75 |
| | 129 |
| | 142 |
|
| Other Income and (Expense): | | | | | | | | | | | | | | |
| Interest expense, net of amounts capitalized | (23 | ) | | (22 | ) | | (45 | ) | | (44 | ) | (22 | ) | | (23 | ) | | (43 | ) | | (45 | ) |
| Other income (expense), net | 1 |
| | — |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Total other income and (expense) | (22 | ) | | (22 | ) | | (44 | ) | | (44 | ) | (21 | ) | | (22 | ) | | (42 | ) | | (44 | ) |
| Earnings Before Income Taxes | 53 |
| | 29 |
| | 98 |
| | 66 |
| 60 |
| | 53 |
| | 87 |
| | 98 |
|
| Income taxes (benefit) | 1 |
| | (3 | ) | | 13 |
| | — |
| (41 | ) | | 1 |
| | (65 | ) | | 13 |
|
| Net Income | 52 |
| | 32 |
| | 85 |
| | 66 |
| 101 |
| | 52 |
| | 152 |
| | 85 |
|
| Less: Net income attributable to noncontrolling interests | 6 |
| | 1 |
| | 6 |
| | 2 |
| 12 |
| | 6 |
| | 13 |
| | 6 |
|
| Net Income Attributable to Southern Power Company | $ | 46 |
| | $ | 31 |
| | $ | 79 |
| | $ | 64 |
| |
| Net Income Attributable to Southern Power | | $ | 89 |
| | $ | 46 |
| | $ | 139 |
| | $ | 79 |
|
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
| | | | For the Three Months
Ended June 30, | | For the Six Months
Ended June 30, | For the Three Months Ended June 30, | | For the Six Months Ended June 30, |
| | 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | (in millions) | | (in millions) | (in millions) | | (in millions) |
| Net Income | $ | 52 |
| | $ | 32 |
| | $ | 85 |
| | $ | 66 |
| $ | 101 |
| | $ | 52 |
| | $ | 152 |
| | $ | 85 |
|
| Other comprehensive income (loss) | — |
| | — |
| | — |
| | — |
| |
| Other comprehensive income (loss): | | | | | | | | |
| Qualifying hedges: | | | | | | | | |
| Changes in fair value, net of tax of $(15), $-, $(15) and $-, respectively | | (24 | ) | | — |
| | (24 | ) | | — |
|
Reclassification adjustment for amounts included in net
income, net of tax of $8, $-, $8, and $-, respectively | | 13 |
| | — |
| | 14 |
| | — |
|
| Total other comprehensive income (loss) | | (11 | ) | | — |
| | (10 | ) | | — |
|
| Less: Comprehensive income attributable to noncontrolling interests | 6 |
| | 1 |
| | 6 |
| | 2 |
| 12 |
| | 6 |
| | 13 |
| | 6 |
|
| Comprehensive Income Attributable to Southern Power Company | $ | 46 |
| | $ | 31 |
| | $ | 79 |
| | $ | 64 |
| |
| Comprehensive Income Attributable to Southern Power | | $ | 78 |
| | $ | 46 |
| | $ | 129 |
| | $ | 79 |
|
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| | | | For the Six Months
Ended June 30, | For the Six Months Ended June 30, |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Operating Activities: | | | | | | |
| Net income | $ | 85 |
| | $ | 66 |
| $ | 152 |
| | $ | 85 |
|
| Adjustments to reconcile net income to net cash provided from operating activities — | | | | | | |
| Depreciation and amortization, total | 121 |
| | 105 |
| 159 |
| | 121 |
|
| Deferred income taxes | 59 |
| | (3 | ) | (71 | ) | | 59 |
|
| Investment tax credits | 153 |
| | 26 |
| — |
| | 153 |
|
| Amortization of investment tax credits | (10 | ) | | (5 | ) | (15 | ) | | (10 | ) |
| Deferred revenues | (21 | ) | | (24 | ) | (31 | ) | | (21 | ) |
| Accrued income taxes, non-current | 100 |
| | — |
| — |
| | 100 |
|
| Other, net | 10 |
| | 7 |
| 9 |
| | 10 |
|
| Changes in certain current assets and liabilities — | | | | | | |
| -Receivables | (26 | ) | | (34 | ) | (76 | ) | | (26 | ) |
| -Fossil fuel stock | 5 |
| | (1 | ) | |
| -Prepaid income taxes | (102 | ) | | 21 |
| (147 | ) | | (102 | ) |
| -Other current assets | — |
| | (1 | ) | 5 |
| | 5 |
|
| -Accounts payable | (31 | ) | | 24 |
| 4 |
| | (31 | ) |
| -Accrued taxes | (110 | ) | | 7 |
| 62 |
| | (110 | ) |
| -Other current liabilities | 18 |
| | 5 |
| — |
| | 18 |
|
| Net cash provided from operating activities | 251 |
| | 193 |
| 51 |
| | 251 |
|
| Investing Activities: | | | | | | |
| Plant acquisitions | (408 | ) | | (213 | ) | |
| Business acquisitions | | (502 | ) | | (408 | ) |
| Property additions | (154 | ) | | (11 | ) | (1,281 | ) | | (154 | ) |
| Change in construction payables | 38 |
| | (3 | ) | (137 | ) | | 38 |
|
| Payments pursuant to long-term service agreements | (45 | ) | | (23 | ) | (43 | ) | | (45 | ) |
| Investment in restricted cash | | (646 | ) | | — |
|
| Distribution of restricted cash | | 649 |
| | — |
|
| Other investing activities | (1 | ) | | (11 | ) | (25 | ) | | (1 | ) |
| Net cash used for investing activities | (570 | ) | | (261 | ) | (1,985 | ) | | (570 | ) |
| Financing Activities: | | | | | | |
| Increase (decrease) in notes payable, net | (195 | ) | | 73 |
| 695 |
| | (195 | ) |
| Proceeds — Senior notes | 650 |
| | — |
| |
| Proceeds — | | | | |
| Senior notes | | 1,241 |
| | 650 |
|
| Capital contributions | | 300 |
| | — |
|
| Distributions to noncontrolling interests | (1 | ) | | — |
| (11 | ) | | (1 | ) |
| Contributions from noncontrolling interests | 78 |
| | 7 |
| |
| Capital contributions from noncontrolling interests | | 179 |
| | 78 |
|
| Purchase of membership interests from noncontrolling interests | | (129 | ) | | — |
|
| Payment of common stock dividends | (65 | ) | | (66 | ) | (136 | ) | | (65 | ) |
| Other financing activities | (3 | ) | | 9 |
| (13 | ) | | (3 | ) |
| Net cash provided from financing activities | 464 |
| | 23 |
| 2,126 |
| | 464 |
|
| Net Change in Cash and Cash Equivalents | 145 |
| | (45 | ) | 192 |
| | 145 |
|
| Cash and Cash Equivalents at Beginning of Period | 75 |
| | 69 |
| 830 |
| | 75 |
|
| Cash and Cash Equivalents at End of Period | $ | 220 |
| | $ | 24 |
| $ | 1,022 |
| | $ | 220 |
|
| Supplemental Cash Flow Information: | | | | | | |
| Cash paid (received) during the period for — | | | | | | |
| Interest (net of $1 and $- capitalized for 2015 and 2014, respectively) | $ | 35 |
| | $ | 43 |
| |
| Interest (net of $21 and $1 capitalized for 2016 and 2015, respectively) | | $ | 42 |
| | $ | 35 |
|
| Income taxes, net | (72 | ) | | (59 | ) | 115 |
| | (72 | ) |
| Noncash transactions — Accrued property additions at end of period | 38 |
| | 5 |
| 108 |
| | 38 |
|
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Assets | | At June 30,
2015 | | At December 31,
2014 | | At June 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Assets: | | | | | | | | |
| Cash and cash equivalents | | $ | 220 |
| | $ | 75 |
| | $ | 1,022 |
| | $ | 830 |
|
| Receivables — | | | | | | | | |
| Customer accounts receivable | | 106 |
| | 77 |
| | 115 |
| | 75 |
|
| Other accounts receivable | | 11 |
| | 15 |
| | 23 |
| | 19 |
|
| Affiliated companies | | 40 |
| | 34 |
| | 60 |
| | 30 |
|
| Fossil fuel stock, at average cost | | 17 |
| | 22 |
| | 14 |
| | 16 |
|
| Materials and supplies, at average cost | | 59 |
| | 58 |
| | 120 |
| | 63 |
|
| Prepaid income taxes | | 122 |
| | 19 |
| | 192 |
| | 45 |
|
| Deferred income taxes, current | | 144 |
| | 306 |
| |
| Other current assets | | 16 |
| | 21 |
| | 31 |
| | 30 |
|
| Total current assets | | 735 |
| | 627 |
| | 1,577 |
| | 1,108 |
|
| Property, Plant, and Equipment: | | | | | | | | |
| In service | | 6,047 |
| | 5,657 |
| | 8,348 |
| | 7,275 |
|
| Less accumulated provision for depreciation | | 1,125 |
| | 1,035 |
| | 1,374 |
| | 1,248 |
|
| Plant in service, net of depreciation | | 4,922 |
| | 4,622 |
| | 6,974 |
| | 6,027 |
|
| Construction work in progress | | 201 |
| | 11 |
| | 1,852 |
| | 1,137 |
|
| Total property, plant, and equipment | | 5,123 |
| | 4,633 |
| | 8,826 |
| | 7,164 |
|
| Other Property and Investments: | | | | | | | | |
| Goodwill | | 2 |
| | 2 |
| | 2 |
| | 2 |
|
Other intangible assets, net of amortization of $10 and $8 at
June 30, 2015 and December 31, 2014, respectively | | 69 |
| | 47 |
| |
Other intangible assets, net of amortization of $14 and $12
at June 30, 2016 and December 31, 2015, respectively | | | 316 |
| | 317 |
|
| Total other property and investments | | 71 |
| | 49 |
| | 318 |
| | 319 |
|
| Deferred Charges and Other Assets: | | | | | | | | |
| Prepaid long-term service agreements | | 141 |
| | 124 |
| | 165 |
| | 166 |
|
| Other deferred charges and assets — affiliated | | 13 |
| | 5 |
| | 23 |
| | 9 |
|
| Other deferred charges and assets — non-affiliated | | 143 |
| | 112 |
| | 173 |
| | 139 |
|
| Total deferred charges and other assets | | 297 |
| | 241 |
| | 361 |
| | 314 |
|
| Total Assets | | $ | 6,226 |
| | $ | 5,550 |
| | $ | 11,082 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| | | Liabilities and Stockholders' Equity | | At June 30,
2015 | | At December 31,
2014 | | At June 30, 2016 | | At December 31, 2015 |
| | | (in millions) | | (in millions) |
| Current Liabilities: | | | | | | | | |
| Securities due within one year | | $ | 525 |
| | $ | 525 |
| | $ | 403 |
| | $ | 403 |
|
| Notes payable | | 8 |
| | 195 |
| | 831 |
| | 137 |
|
| Accounts payable — | | | | | | | | |
| Affiliated | | 65 |
| | 78 |
| | 80 |
| | 66 |
|
| Other | | 55 |
| | 30 |
| | 175 |
| | 327 |
|
| Accrued taxes — | | | | | |
| Accrued income taxes | | 7 |
| | 72 |
| | 9 |
| | 198 |
|
| Other accrued taxes | | | 16 |
| | 5 |
|
| Accrued interest | | 31 |
| | 30 |
| | 22 |
| | 23 |
|
| Contingent consideration | | | 23 |
| | 36 |
|
| Other current liabilities | | 53 |
| | 17 |
| | 69 |
| | 44 |
|
| Total current liabilities | | 744 |
| | 947 |
| | 1,628 |
| | 1,239 |
|
| Long-term Debt | | 1,737 |
| | 1,095 |
| | 3,929 |
| | 2,719 |
|
| Deferred Credits and Other Liabilities: | | | | | | | | |
| Accumulated deferred income taxes | | 760 |
| | 863 |
| | 524 |
| | 601 |
|
| Accumulated deferred investment tax credits | | 693 |
| | 601 |
| | 1,107 |
| | 889 |
|
| Accrued income taxes, non-current | | 100 |
| | — |
| | 109 |
| | 109 |
|
| Asset retirement obligations | | | 28 |
| | 21 |
|
| Deferred capacity revenues — affiliated | | 9 |
| | 15 |
| | 7 |
| | 17 |
|
| Other deferred credits and liabilities — affiliated | | — |
| | 1 |
| |
| Other deferred credits and liabilities — non-affiliated | | 22 |
| | 18 |
| |
| Other deferred credits and liabilities | | | 105 |
| | 3 |
|
| Total deferred credits and other liabilities | | 1,584 |
| | 1,498 |
| | 1,880 |
| | 1,640 |
|
| Total Liabilities | | 4,065 |
| | 3,540 |
| | 7,437 |
| | 5,598 |
|
| Redeemable Noncontrolling Interest | | 41 |
| | 39 |
| |
| Redeemable Noncontrolling Interests | | | 47 |
| | 43 |
|
| Common Stockholder's Equity: | | | | | | | | |
| Common stock, par value $.01 per share — | | | | | | | | |
| Authorized — 1,000,000 shares | | | | | | | | |
| Outstanding — 1,000 shares | | — |
| | — |
| | — |
| | — |
|
| Paid-in capital | | 1,176 |
| | 1,176 |
| | 2,121 |
| | 1,822 |
|
| Retained earnings | | 587 |
| | 573 |
| | 661 |
| | 657 |
|
| Accumulated other comprehensive income | | 4 |
| | 3 |
| |
| Accumulated other comprehensive income (loss) | | | (6 | ) | | 4 |
|
| Total common stockholder's equity | | 1,767 |
| | 1,752 |
| | 2,776 |
| | 2,483 |
|
| Noncontrolling Interest | | 353 |
| | 219 |
| |
| Total Stockholders' Equity | | 2,120 |
| | 1,971 |
| |
| Noncontrolling interests | | | 822 |
| | 781 |
|
| Total stockholders' equity | | | 3,598 |
| | 3,264 |
|
| Total Liabilities and Stockholders' Equity | | $ | 6,226 |
| | $ | 5,550 |
| | $ | 11,082 |
| | $ | 8,905 |
|
The accompanying notes as they relate to Southern Power are an integral part of these consolidated financial statements.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SECOND QUARTER 20152016 vs. SECOND QUARTER 20142015
AND
YEAR-TO-DATE 20152016 vs. YEAR-TO-DATE 20142015
OVERVIEW
Southern Power constructs, acquires, owns, and manages 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 of new power plants, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and electric cooperatives.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 six months ended June 30, 2015,2016, Southern Power acquired or commenced construction of approximately 353333 MWs of additional solar and wind facilities including the five Georgia construction projects located in Taylor and Butler Counties, as well as the Lost Hills, Blackwell,committed to acquire approximately 656 MWs of solar and North Star projects located in California.wind facilities. Subsequent to June 30, 2016, Southern Power also entered into an agreement to acquire anacquired or commenced construction of approximately 299-MW wind facility, located in Oklahoma, contingent upon certain construction and project milestones.278 MWs of solar facilities. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions"Acquisitions" and "Construction Projects""Construction Projects" herein for additional information.
At June 30, 2016, Southern Power had an average investment coverage ratio of 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025) with an average remaining contract duration of approximately 17 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 include 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
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $15 | | 48.4 | | $15 | | 23.4 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $43 | | 93.5 | | $60 | | 75.9 |
Net income attributable to Southern Power for the second quarter 20152016 was $46$89 million compared to $31$46 million for the corresponding period in 2014. The increase was primarily due to increased revenue and lower fuel and purchased power expenses.
2015. Net income attributable to Southern Power for year-to-date 20152016 was $79$139 million compared to $64$79 million for the corresponding period in 2014.2015. The increase wasincreases were primarily due to a decrease in purchased power expenses,increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation and income taxes.operations and maintenance expenses all related to new solar and wind facilities placed in service.
Wholesale
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Operating Revenues–Non-Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(10) | | (3.8) | | $(57) | | (10.6) |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $36 | | 10.7 | | $4 | | 0.6 |
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, it may sell power into the wholesale market or into the power pool.
|
| | | | | | | | | | | |
| | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | (change in millions) | | (% change) | | (change in millions) | | (% change) |
| PPA capacity revenues | $ | (2 | ) | | (1.8) | | $ | (5 | ) | | (1.9) |
| PPA energy revenues | 17 |
| | 11.6 | | 18 |
| | 6.7 |
| Total PPA revenues | 15 |
|
| 5.2 | | 13 |
| | 2.5 |
| Revenues not covered by PPA | 21 |
| | 43.7 | | (9 | ) | | (6.2) |
| Total operating revenues | $ | 36 |
| | 10.7% | | $ | 4 |
| | 0.6% |
In the second quarter 2016, operating revenues were $373 million compared to $337 million for the corresponding period in 2015. The $36 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $2 million as a result of a $10 million decrease in non-affiliate capacity revenues, partially offset by an $8 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.
PPA energy revenuesincreased $17 million primarily due to a $37 million increase in renewable energy sales, arising from new solar and wind facilities, partially offset by a decrease of $20 million in fuel revenues related to natural gas facility PPAs.
Revenues not covered by PPA increased $21 million due to a $15 million increase related to short-term sales to non-affiliates and a $6 million increase primarily due to a 30% increase in KWH sales to the power pool driven by lower natural gas prices.
For year-to-date 2016, operating revenues were $688 million compared to $684 million for the corresponding period in 2015. The $4 million increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $5 million as a result of a $26 million decrease in non-affiliate capacity revenues, partially offset by a $21 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.
PPA energy revenuesincreased $18 million primarily due to a $58 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $40 million in fuel revenues related to natural gas facility PPAs.
Revenues not covered by PPA decreased $9 million due to a $25 million decrease primarily related to a 21% decrease in volume of sales into the power pool associated with increased scheduled outages and a reduction in demand driven by milder weather, partially offset by lower natural gas prices. The decrease was partially offset by a $16 million increase related to short-term sales to non-affiliates.
Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of thoseSouthern 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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Wholesale revenuesSouthern Power's electricity sales from non-affiliates forsolar and wind generating facilities are also through long-term PPAs, but do not have a capacity charge. Instead, the second quarter 2015 were $250 million compared to $260 million forcustomers purchase the corresponding period in 2014. The decrease was due toenergy output of a $5 million decrease indedicated renewable facility through an energy sales, primarily ascharge. As a result, of decreased fuel costs passed through in PPA revenues dueSouthern Power's ability to lower natural gas prices, partially offset by increased sales volumesrecover fixed and new solar PPAs. The decrease in energy revenues reflects a 14% decrease invariable operations and maintenance expenses is dependent upon the average pricelevel of energy partially offsetgenerated from these facilities, which can be impacted by a 12% increase in KWH sales. In addition, capacity revenues decreased $5 million primarily due to PPA expirations.
Wholesale revenues from non-affiliates for year-to-date 2015 were $481 million compared to $538 million for the corresponding period in 2014. The decrease was due to a $44 million decrease in energy sales, primarily as a result of decreased fuel costs passed through in PPA revenues due to lower natural gas prices, partially offset by increased sales volumesweather conditions, equipment performance, and new solar PPAs. The decrease in energy revenues reflects a 17% decrease in the average price of energy, partially offset by a 5% increase in KWH sales. In addition, capacity revenues decreased $13 million primarily due to PPA expirations.
Wholesale Revenues–Affiliates
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $17 | | 25.0 | | $59 | | 42.1 |
Wholesale revenues from sales to affiliate companies will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.
Wholesale revenues from affiliates for the second quarter 2015 were $85 million compared to $68 million for the corresponding period in 2014. The increase was the result of a $10 million increase in energy revenues and a $7 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 61% increase in KWH sales, partially offset by a 21% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.
Wholesale revenues from affiliates for year-to-date 2015 were $199 million compared to $140 million for the corresponding period in 2014. The increase was the result of a $50 million increase in energy revenues and a $9 million increase in capacity revenues. The increase in energy revenues is primarily the result of increased sales volume under the IIC as a result of lower natural gas prices, which increased demand for Southern Power Company's resources. The increase in energy revenues reflects a 110% increase in KWH sales, partially offset by a 22% decrease in the average price of energy. The increase in capacity revenues was primarily the result of new PPAs.other factors.
Fuel and Purchased Power Expenses
Fuel costs constitute the single largest expense for Southern Power. Additionally, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:
|
| | | | | | | | | | | | | |
| | | Second Quarter 2015
vs.
Second Quarter 2014 | | Year-to-Date 2015
vs.
Year-to-Date 2014 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (13 | ) | | (11.0) | | $ | — |
| | — |
|
| Purchased power – non-affiliates | | 1 |
| | 5.9 | | (11 | ) | | (24.4 | ) |
| Purchased power – affiliates | | (12 | ) | | (75.0) | | (32 | ) | | (69.6 | ) |
| Total fuel and purchased power expenses | | $ | (24 | ) | | | | $ | (43 | ) | | |
|
| | | | | |
| | Second Quarter 2016 | Second Quarter 2015 | | Year-to-Date 2016 | Year-to-Date 2015 |
Generation (in billions of KWHs) | 9.1 | 7.5 | | 16.7 | 15.4 |
Purchased power (in billions of KWHs) | 0.9 | 0.5 | | 1.5 | 0.9 |
| Total generation and purchased power | 10.0 | 8.0 | | 18.2 | 16.3 |
Total generation and purchased power excluding solar, wind, and tolling agreements | 5.7 | 4.8 | | 11.0 | 10.7 |
Southern Power's PPAs for natural gas-firedgas 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.fuel relating to the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel costcosts is generally
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
accompanied by an increase or decrease in related fuel revenues under the PPAs and does 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 sold to affiliates underinto the IIC.power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).
Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, Company, affiliate companies, or external parties.
In the second quarter 2015, total fuel and purchased power expenses were $127 million compared to $151 million for the corresponding period in 2014. The decrease was the result of a $58 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $34 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
For year-to-date 2015, total fuel and purchased power expenses were $291 million compared to $334 million for the corresponding period in 2014. The decrease was a result of a $154 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $111 million net increase in the total volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.
Fuel
In the second quarter 2015, fuel expense was $105 million compared to $118 million for the corresponding period in 2014. The decrease was due to a 36.1% decrease associated with the average cost of natural gas per KWH generated, partially offset by a 40.6% increase associated with the volume of KWHs generated, primarily as a result of increased demand resulting from lower natural gas prices.
For year-to-date 2015 and for the corresponding period in 2014, fuel expense was $243 million. While there was no overall change, a $152 million increase in the total cost of fuel attributable to the volume of KWHs generated was offset by a $152 million decrease in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates and Affiliates
In the second quarter 2015, purchased power expense was $22 million compared to $33 million for the corresponding period in 2014. For year-to-date 2015, purchased power expense was $48 million compared to $91 million for the corresponding period in 2014. The decreases were primarily the result of 37.4% and 45.6% decreases in the volume of KWHs purchased in the second quarter 2015 and year-to-date 2015, respectively, primarily due to lower natural gas prices which resulted in higher use of Southern Power Company's generation resources.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $— | | — | | $(1) | | (0.8) |
|
| | | | | | | | | | | | |
| | | Second Quarter 2016
vs.
Second Quarter 2015 | | Year-to-Date 2016
vs.
Year-to-Date 2015 |
| | | (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| Fuel | | $ | (9 | ) | | (8.6) | | $ | (56 | ) | | (23.0) |
| Purchased power | | 1 |
| | 4.5 | | (5 | ) | | (10.4) |
| Total fuel and purchased power expenses | | $ | (8 | ) | | | | $ | (61 | ) | | |
In the second quarter 2015 and for the corresponding period in 2014, other operations and maintenance expenses were $69 million. While there was no overall change, a decrease in outage expense of $10 million was offset by a $10 million increase in expenses associated with support services, transmission, and new plants placed in service in 2014 and 2015.
For year-to-date 2015, other operations and maintenance expenses were $121 million compared to $122 million for the corresponding period in 2014. The decrease was primarily due to a $17 million decrease in outage expense,
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In the second quarter 2016, total fuel and purchased power expenses were $119 million compared to $127 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $9 million primarily due to a $22 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $13 million increase associated with the volume of KWHs generated.
Purchased power expense increased $1 million due to a $13 million increase associated with the volume of KWHs purchased, largely offset by an $8 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration.
For year-to-date 2016, total fuel and purchased power expenses were $230 million compared to $291 million for the corresponding period in 2015. The decrease was primarily due to the following:
Fuel expense decreased $56 million primarily due to a $51 million decrease associated with the average cost of natural gas per KWH generated and a $5 million decrease associated with the volume of KWHs generated.
Purchased power expense decreased $5 million due to a $21 million decrease in the average cost of purchased power and an $8 million decrease associated with a PPA expiration, largely offset by a $16$24 million increase associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $17 | | 24.6 | | $41 | | 33.9 |
In the second quarter 2016, other operations and maintenance expenses were $86 million compared to $69 million for the corresponding period in 2015. The increase was primarily due to an $8 million increase in expenses associated with support services, new plantssolar and wind facilities placed in service in 2014 and 2015 and transmission.2016, a $5 million increase in general business expenses associated with Southern Power's overall growth strategy, and a $4 million increase associated with scheduled outage and maintenance expenses.
For year-to-date 2016, other operations and maintenance expenses were $162 million compared to $121 million for the corresponding period in 2015. The increase was primarily due to an $18 million increase associated with scheduled outage and maintenance expenses, a $13 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $10 million increase in general business expenses associated with Southern Power's overall growth strategy.
Depreciation and Amortization
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $8 | | 15.4 | | $15 | | 14.6 |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $21 | | 35.0 | | $36 | | 30.5 |
In the second quarter 2015,2016, depreciation and amortization was $60$81 million compared to $52$60 million for the corresponding period in 2014.2015. For year-to-date 2015,2016, depreciation and amortization was $118$154 million compared to $103$118 million for the corresponding period in 2014.2015. The increases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 20142015 and 2016.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense, net of Amounts Capitalized
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
| $(1) | | (4.3) | | $(2) | | (4.4) |
In the second quarter 2016, interest expense, net of amounts capitalized was $22 million compared to $23 million for the corresponding period in 2015. The decrease was primarily due to an $11 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $10 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.
For year-to-date 2016, interest expense, net of amounts capitalized was $43 million compared to $45 million for the corresponding period in 2015. The decrease was primarily due to a $20 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $18 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.
Income Taxes (Benefit)
|
| | | | | | |
| Second Quarter 2015 vs. Second Quarter 2014 | | Year-to-Date 2015 vs. Year-to-Date 2014 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $4 | | 133.3 | | $13 | | N/M |
|
| | | | | | |
| Second Quarter 2016 vs. Second Quarter 2015 | | Year-to-Date 2016 vs. Year-to-Date 2015 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) |
| $(42) | | N/M | | $(78) | | N/M |
N/M –- Not meaningful
In the second quarter 2015,2016, income taxes were $1tax benefit was $(41) million compared to an income tax benefitexpense of $3$1 million for the corresponding period in 2014. For year-to-date 2015, income taxes were $13 million.2015. The increases werechange was primarily due to higher pre-tax earningsa $46 million increase in 2015 and beneficial state income tax changes in 2014, partially offset by increased federal income tax benefits from solar ITCs and wind PTCs in 2016, partially offset by a $4 million increase in tax expense related to beneficial state apportionment rate changes in 2015.
For year-to-date 2016, income tax benefit was $(65) million compared to an expense of $13 million for the corresponding period in 2015. The change was primarily due to a $75 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $7 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $4 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 includeinclude: 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; and Southern Power's ability to execute its acquisition and value creationgrowth strategy, including successfully expandingsuccessful additional investments in renewable and other energy projects, and to construct generating facilities, including the impact of federal ITCs.ITCs and PTCs. 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.
Other factors that could influence future earnings include weather, demand, cost of generatinggeneration from units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 December 31, 2015, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% for the next five years (through 2020) and 70% for the next 10 years (through 2025), with an average remaining contract duration of approximately 10 years.
Southern Power believes an investment coverage ratio better identifies the value of assets covered since it represents the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. At June 30, 2016, the investment coverage ratio was 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 17 years. At December 31, 2015, the investment coverage ratio would have been 91% for the next five years (through 2020) and 90% for the next 10 years (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 regulatory or legislative changes cannot be determined at this time.
Acquisitions
During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Air Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Power in Item 7 |
| | | | | | |
| Project Facility | Resource | Approx. Nameplate Capacity | Location | Percentage Ownership | Expected/Actual COD | PPA Contract Period |
| | | (MW) | | | | |
| Acquisitions During the Six Months Ended June 30, 2016 |
| Calipatria | Solar | 20 | Imperial County, CA | 90% | February 2016 | 20 years |
| East Pecos | Solar | 120 | Pecos County, TX | 100% | Fourth quarter 2016 | 15 years |
| Grant Wind | Wind | 151 | Grant County, OK | 100% | April 2016 | 20 years |
| Passadumkeag | Wind | 42 | Penobscot County, ME | 100% | July 2016 | 15 years |
| Acquisitions Subsequent to June 30, 2016 |
| Henrietta | Solar | 102 | Kings County, CA | 51%(*) | July 2016 | 20 years |
| Lamesa | Solar | 102 | Dawson County, TX | 100% | Second quarter 2017 | 15 years |
| Rutherford | Solar | 74 | Rutherford County, NC | 90% | Fourth quarter 2016 | 15 years |
| |
| (*) | 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. |
Acquisitions During the Form 10-KSix Months Ended June 30, 2016
Total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million for additional information regarding the EPA's proposed regulations governing emissions during startup, shutdown, or malfunction (SSM) and the Cross State Air Pollution Rule (CSAPR).
On June 12, 2015, the EPA published a final rule requiring affected states (including Alabama, Florida, Georgia, North Carolina, and Texas) to revise or remove state implementation plan (SIP) provisions regarding excess emissions that occur during periods of SSM by no later than November 22, 2016.East Pecos, which is currently under construction. The ultimate impact of the final rule will depend on the outcome of any legal challenges and the development and approval of SIPs by the affected states andthis matter cannot be determined at this time.
On July 28, 2015,Acquisitions Subsequent to June 30, 2016
Total aggregate construction costs, excluding the U.S. Court of Appealsacquisition costs, are expected to be approximately $260 million to $300 million for the District of Columbia Circuit issued an opinion invalidating certain emissions budgetsLamesa and Rutherford, which are currently under the CSAPR Phase II emissions trading program for a number of states, including Alabama, Florida, Georgia, North Carolina, and Texas. The court's decision leaves the emissions trading program in place and remands the rule to the EPA for further action consistent with the court's decision. The court rejected all other pending challenges to the rule.construction. The ultimate impactoutcome of this decision will depend on additional rulemaking andthese matters cannot be determined at this time.
Global Climate IssuesAcquisition Agreements Executed but Not Yet Closed
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" ofDuring the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in Item 7two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Form 10-K for additional information regarding the EPA's proposed regulationClass A membership interests entitling Southern Power to 51% of CO2 from fossil-fuel-fired electric generating units.
On August 3, 2015, the EPA released pre-publication versions of two final rules that would limit CO2 emissions from fossil fuel-fired electric generating units. Oneall cash distributions and significantly all of the final rules contains specific emission standards governing CO2 emissions from new, modified,federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and reconstructed units.a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. The other final rule establishes guidelines for states to develop plans to meet EPA-mandated CO2 emission rates for existing units. The EPA's final guidelines require state plans to meet interim CO2 performance rates between 2022 and 2029 and final rates in 2030 and thereafter. At the same time, the EPA also proposed a federal plan and proposed model rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. These guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, which could affect future unit retirement and replacement decisions. Southern Power's resultsultimate outcome of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through existing PPAs. However, the ultimate financial and operational impact of the final rules on Southern Powerthese matters cannot be determined at this timetime.
The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 million. The aggregate amount of net income, excluding impacts of ITCs and will depend on numerous factors includingPTCs, attributable to Southern Power related to the Southern Company system's ongoing reviewproject facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the final rules;beginning of 2016 and for the outcome of any legal challenges; individual state implementation of the EPA's final guidelines, including the potential that state plans impose different standards; additional rulemaking activities in response to legal challengescomparable 2015 period is not meaningful and related court decisions; the impact of future changes in generation and emissions related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.has been omitted.
Acquisitions
During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015.
Kay County Wind Facility
On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
Lost Hills-Blackwell Solar Facilities
On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years.
North Star Solar Facility
On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company.
Construction Projects
In December 2014,See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired allin Item 7 of the outstanding membership interests of five separate solar project development entities. The construction projects areForm 10-K for additional information.
During the six months ended June 30, 2016, in accordance with Southern Power'sits overall growth strategy, Southern Power completed construction of and includedplaced in its capital program estimates for 2015. Theservice the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through June 30, 2016, total costcosts of construction incurred for thesethe projects through June 30, 2015 was $188 million.below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. 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
Southern Power Company's construction projects are detailed in the table below:
|
| | | | | | | | | | | | |
| Solar Project | Seller | Nameplate Capacity | County Location in Georgia | Expected Commercial Operation Date | PPA Counterparty
for Entire Plant Output | PPA Contract Period | Estimated Construction Cost | |
| | | (MW) | | | | | (in millions) | |
| Taylor County | N/A | 146 | Taylor | Fourth quarter 2016 | Cobb, Flint, and Sawnee Electric Membership Corporations | 25 years | $ | 260 |
| - | $280 | |
| Decatur Parkway | TradeWind Energy, Inc. | 84 | Decatur | December 2015 | Georgia Power(a) | 25 years | $ | 170 |
| - | $173 | (b) |
| Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 2015 | Georgia Power(a) | 20 years | $ | 45 |
| - | $47 | (b) |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | December 2016 | Georgia Power(a) | 30 years | $ | 220 |
| - | $230 | (b) |
| Pawpaw | Longview Solar, LLC | 30 | Taylor | December 2015 | Georgia Power(a) | 30 years | $ | 70 |
| - | $80 | (b) |
| Butler Solar Farm | Strata Solar Development, LLC | 20 | Taylor | December 2015 | Georgia Power(a) | 20 years | $ | 42 |
| - | $48 | (b) |
|
| | | | |
| Solar Facility | Approx. Nameplate Capacity | Location | Expected/Actual COD | PPA Contract Period |
| (MW) | | | |
| Butler | 103 | Taylor County, GA | Fourth quarter 2016 | 30 years |
Desert Stateline(a) | 299(b) | San Bernardino County, CA | Through third quarter 2016 | 20 years |
Garland and
Garland A | 205 | Kern County, CA | Fourth quarter 2016 and
Third quarter 2016 | 15 years and
20 years |
| Roserock | 160 | Pecos County, TX | Fourth quarter 2016 | 20 years |
| Sandhills | 146 | Taylor County, GA | Fourth quarter 2016 | 25 years |
| Tranquillity | 205 | Fresno County, CA | July 2016 | 18 years |
| |
| (a) | Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. |
| |
| (b) | Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service. |
(a) Subject to FERC approval.
(b) Includes the acquisition price of all outstanding membership interests.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital"Capital Requirements and Contractual Obligations"Obligations" herein for additional information.
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 with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.
Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of June 30, 2015 from the period ended December 31, 2014.
FERC Matters
Southern Power has authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC directed the traditional 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 operating companies and Southern Power filed a request for rehearing on May 27, 2015 and on June 26, 2015 filed their response with the FERC. 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
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.
TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthern Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthern 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 policies and estimates related to Revenue Recognition, Impairment of Long LivedLong-Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.
Recently Issued Accounting Standards
The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revises the accounting for revenue recognition effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.
On February 18, 2015,25, 2016, the FASB issued Accounting Standards Update (ASU) 2015-02,ASU No. 2016-02, AmendmentsLeases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the Consolidation Analysis, which makes certainbalance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes to both the variable interest modelrecognition, measurement, and the voting model, including changes topresentation of expense associated with leases and provides clarification regarding the identification of variable interests, the variable interest entity characteristics forcertain components of contracts that would represent a limited partnership or similar entity, and the primary beneficiary determination. Thislease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2015.2018, with early adoption permitted. Southern Power is currently evaluating these requirements. The ultimate impact of this ASUthe new standard and has not yet been determined.determined its ultimate impact.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
Overview
Southern Power's financial condition remained stable at June 30, 2015.2016. 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"Sources of Capital"Capital" herein for additional information on lines of credit.
Net cash provided from operating activities totaled $51 million for the first six months of 2016, compared to $251 million for the first six months of 2015, compared to $193 million for the first six months of 2014.2015. The increasedecrease in cash provided from operating activities was primarily due to lower purchased power costs and an increase in income tax benefits received.taxes paid. Net cash used for investing activities totaled $570 million$2.0 billion for the first six months of 20152016 primarily due to the Lost Hills, Blackwell, and North Star acquisitions and expenditures related to the construction of new solarrenewable facilities. Net cash provided from financing activities totaled $464 million$2.1 billion for the first six months of 20152016 primarily due to the issuance of additionalan increase in senior notes in May 2015. Fluctuations in cash flowand notes payable. 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 six months of 20152016 include a $300$715 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $947 million increase in plant in service, net of depreciation primarily due to the Lost Hills, Blackwell,solar and North Star acquisitions and a $190 million increasewind facilities being placed in CWIP primarily due to the construction of new solar facilities.service. Other significant changes include ana $192 million increase in cash and cash equivalents and a $1.9 billion increase in notes payable and long-term debt of $642 million primarily as a result of the issuance of senior notes in May 2015.due to additional borrowings to fund acquisitions and construction projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" 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 Southern Power in Item 7 of the Form 10-K for a 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, purchase commitments, and unrecognized tax benefits. Subsequentbenefits, and other purchase commitments. Approximately $400 million will be required to June 30, 2015, $525 million ofrepay long-term debt was repaid at maturity.due September 28, 2016. There are no other scheduled maturities of long-term debt through June 30, 2016.2017. In addition, during the six months ended
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 2016, Southern Power entered into new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $784 million.
The capitalconstruction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction. In addition, the construction as well as ongoingprogram includes capital improvements and work to be performed under long-term service agreements.LTSAs. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to betotal approximately $1.4$4.5 billion for 2015,2016, which includes approximately $1.3$4.4 billion for acquisitions and/or construction of new generating facilities. See Note (I)Capital expenditures of Southern Power are currently estimated to the Condensed Financial Statements hereintotal approximately $1.0 billion and $1.5 billion for additional information.2017 and 2018, respectively. Actual capital costs may vary from these estimates because of numerous factors such as: changes in factors such as 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, 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.
As of June 30, 2016, Southern Power's current liabilities sometimes exceedexceeded current assets by $51 million due to long-term debt maturing in 2016, the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, which can fluctuate significantly due to both seasonality and the seasonalitystage of the business.acquisitions and construction projects. In 2015,2016, Southern Power has utilized the capital markets to issue additional senior notes and expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its maturities.
As of June 30, 2016, Southern Power had cash and cash equivalents of approximately $1.0 billion.
Details of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Short-term Debt at June 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 | | $ | 62 |
| | 0.8 | % | | $ | 194 |
| | 0.8 | % | | $ | 310 |
|
| |
| (*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2016. |
Company Facility
At June 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $560 million was unused. Southern Power's subsidiaries are not borrowers under the Facility.
The Facility, as well as Southern Power's term 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 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
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
markets, bank term loans, and commercial paper markets, ascapitalization excludes the source of funds for the majority of its maturities andcapital stock or other equity attributable to meet short-term liquidity needs, including funding acquisition and construction costs.
To meet liquidity and capital resource requirements,such subsidiary. Southern Power had at June 30, 2015 cash and cash equivalents of approximately $220 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $466 million is unused.
The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.
Proceeds from thisthe Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company'sPower's commercial paper program. Subject to applicable market conditions, Southern Power Company expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power Company 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"Bank Credit Arrangements"Arrangements" herein for additional information.
Southern Power Company'sPower'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. SubsequentSouthern Power's subsidiaries are not borrowers under the commercial paper program.
Subsidiary Facilities
In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings 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. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of June 30, 2015, commercial paper was used to partially fund the maturity2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Loan Facility Total | | Total Loan Facility Undrawn | | Letter of Credit Facility | | Total Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Tranquillity | | Earlier of PPA COD or December 31, 2016 | | $ | 86 |
| | $ | 172 |
| | $ | 258 |
| | $ | 19 |
| | $ | 77 |
| | $ | 26 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016 | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Garland | | Earlier of PPA COD or November 30, 2016 | | 86 |
| | 308 |
| | 394 |
| | 73 |
| | 49 |
| | 23 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 126 |
| | $ | 149 |
| | $ | 65 |
|
The Project Credit Facilities had total amounts outstanding as of long-term debt in July 2015.
DetailsJune 30, 2016 of short-term borrowings were as follows:
|
| | | | | | | | | | | | | | | | | | |
| | | Commercial Paper at the End of the Period | | Commercial Paper During the Period(*) |
| | | Amount Outstanding | | Weighted Average Interest Rate | | Average Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| | | (in millions) | | | | (in millions) | | | | (in millions) |
| June 30, 2015: | | $ | — |
| | — | % | | $ | 163 |
| | 0.6 | % | | $ | 339 |
|
(*) Average and maximum amounts are based upon daily balances during$769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2015.2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.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.
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 Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2015 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and Baa2 | $ | 9 |
|
| At BBB- and/or Baa3 | 320 |
|
| Below BBB- and/or Baa3 | 1,081 |
|
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.
The maximum potential collateral requirements under these contracts at June 30, 2016 were as follows:
|
| | | |
| Credit Ratings | Maximum Potential
Collateral
Requirements |
| | (in millions) |
| At BBB and/or Baa2 | $ | 29 |
|
| At BBB- and/or Baa3 | $ | 377 |
|
| Below BBB- and/or Baa3 | $ | 1,086 |
|
Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, anya credit rating downgrade could impact the ability of Southern Power's abilityPower to access capital markets particularlyand would be likely to impact the short-term debt market.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 Company'sPower's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.
Financing Activities
During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In May 2015,addition, Southern Power's subsidiaries issued $16 million in letters of credit. Subsequent to June 30, 2016, Southern Power's subsidiaries borrowed $48 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.98%.
In June 2016, Southern Power Company issued $350€600 million aggregate principal amount of Series 2015A 1.500%2016A 1.00% Senior Notes due June 1, 201820, 2022 and $300€500 million aggregate principal amount of Series 2015B 2.375%2016B 1.85% Senior Notes due June 1, 2020.20, 2026. The proceeds were usedwill be allocated to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, includingrenewable energy generation projects. Southern Power's growth strategyobligations 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 continuous construction program, andprincipal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.additional information.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
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
(UNAUDITED)
INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
|
| | |
| Note | | Page Number |
| A | | |
| B | | |
| C | | |
| D | | |
| E | | |
| F | | |
| G | | |
| H | | |
| I | | |
| J | | |
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 |
| 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 |
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY 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, 20142015 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 June 30, 20152016 and 2014.2015. 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.
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.
On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In March 2015, in connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.
In June 2015, Georgia Power identified an error affecting the billing to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing from January 1, 2013 to June 30, 2015. In the second quarter 2015, Georgia Power recorded an out of period adjustment of approximately $75 million to decrease retail revenues, resulting in a decrease to net income of approximately $47 million. Georgia Power evaluated the effects of this error on the interim and annual periods that included the billing error, as well as the current period. Based on an analysis of qualitative and quantitative factors, Georgia Power determined the error was not material to any affected period and, therefore, an amendment of previously filed financial statements was not required.
Recently Issued Accounting Standards
On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The Financial Accounting Standards Board's (FASB) ASC 606, Revenue from Contracts with Customers, revisesaccounting required by lessors is relatively unchanged and there is no change to the accounting for revenue recognitionexisting leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2017.2018, with early adoption permitted. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact ofare currently evaluating the new standard hasand have not yet been determined.determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company and the traditional electric operating companies' 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 benefit in the income statement. Southern Company and the traditional electric operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company and the traditional
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On February 18, 2015,electric operating companies intend to adopt the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.
On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability andfourth quarter 2016. The adoption is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not expected to have a material impact on the results of operations, financial position, or cash flows of any registrant.Southern Company and the traditional electric operating companies.
Affiliate Transactions
In 2014, prior to Southern Company's acquisition 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 $102 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at June 30, 2016. PowerSecure construction service costs of approximately $13 million are included in accounts payable, affiliated in Georgia Power's balance sheet at June 30, 2016. The facilities will be owned and operated by Georgia Power and are expected to be operational by the end of 2016. The ultimate outcome of this matter cannot be determined at this time.
See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.
On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 19, 2015 as the effective date of the CCR Rule. Therefore, Alabama Power, Gulf Power, and Mississippi Power recorded new asset retirement obligations (ARO) for facilities that are subject to the CCR Rule. Georgia Power had previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule. The cost estimates below are based on information that was known as of June 30, 20152016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule requirements.Disposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in place or by other methods. As further analysis is performed, including evaluation of the expected timing and method of compliance, and 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.
As of June 30, 2015,2016, details of the AROs, including those related to the CCR Rule,asset retirement obligations (ARO) included in Southern Company's and the traditional operating companies'registrants' Condensed Balance Sheets herein were as follows:
| | | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | (in millions) | (in millions) |
| Balance at beginning of year | $ | 2,201 | | | $ | 829 | | | $ | 1,255 | | | $ | 17 | | | $ | 48 | | $ | 3,759 |
| | $ | 1,448 |
| | $ | 1,916 |
| | $ | 130 |
| | $ | 177 |
| | $ | 21 |
|
| Liabilities incurred | 612 | | | 401 | | | — | | | 71 | | | 97 | | 9 |
| | 5 |
| | — |
| | — |
| | — |
| | 4 |
|
| Liabilities settled | (10 | ) | | (1 | ) | | (9 | ) | | — | | | — | | (66 | ) | | (6 | ) | | (52 | ) | | (1 | ) | | (7 | ) | | — |
|
| Accretion | 53 | | | 23 | | | 28 | | | — | | | 1 | | 77 |
| | 36 |
| | 34 |
| | 1 |
| | 2 |
| | 1 |
|
| Cash flow revisions | 58 | | | — | | | 82 | | | 4 | | | 2 | | 699 |
| | 19 |
| | 673 |
| | 3 |
| | 6 |
| | 2 |
|
| Balance at end of period | $ | 2,914 | | | $ | 1,252 | | | $ | 1,356 | | | $ | 92 | | | $ | 148 | | $ | 4,478 |
| | $ | 1,502 |
| | $ | 2,571 |
| | $ | 133 |
| | $ | 178 |
| | $ | 28 |
|
The traditional electric operating companies' increases in liabilities incurred and cash flow revisions for the six months ended June 30, 20152016 primarily relate to anchanges in ash pond closure strategy. The increase for Georgia Power was due to its decision in AROs associated with facilities impactedJune 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 CCR Rule.beneficial use of coal ash or through closure in place using advanced engineering methods.
In connection with a proposed settlement related to the closure of Plant Scholz, Gulf Power may incur additional AROs associated with CCR of approximately $15 million to $35 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Goodwill and Other Intangible Assets
Goodwill and other intangible assets consisted of the following:
|
| | | | | | | | | | |
| | At June 30, 2016 |
| | Estimated Useful Life | Gross Carrying Amount | Accumulated Amortization | Intangible Assets, Net |
| | | (in millions) |
| Intangibles subject to amortization: | | | | |
| Southern Company | | | | |
| Customer relationships | 14-26 years | $ | 47 |
| $ | — |
| $ | 47 |
|
| Trade names | 5-9 years | 43 |
| — |
| 43 |
|
| Patents | 3-10 years | 4 |
| — |
| 4 |
|
| Backlog | 5 years | 5 |
| — |
| 5 |
|
| Southern Power | | | | |
| PPA fair value adjustments | 20 years | 330 |
| (14 | ) | 316 |
|
| Total intangibles subject to amortization | | $ | 429 |
| $ | (14 | ) | $ | 415 |
|
| | | | | |
| Intangibles not subject to amortization: | | | | |
| Southern Company | | | | |
| Federal Communications Commission licenses | | $ | 75 |
| $ | — |
| $ | 75 |
|
| | | | | |
| Goodwill: | | | | |
| Southern Company | | $ | 262 |
| $ | — |
| $ | 262 |
|
| Southern Power | | 2 |
| — |
| 2 |
|
| Total goodwill and other intangible assets | | $ | 768 |
| $ | (14 | ) | $ | 754 |
|
Amortization expense associated with intangible assets during the three and six months ended June 30, 2016 was immaterial.
Intangibles at December 31, 2015 consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangibles relate to Southern Company's acquisition of PowerSecure on May 9, 2016.
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. See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.
| |
| (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
Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
Environmental Matters
New Source Review Actions
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions sought penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) was partially settled in 2006 through a consent decree with the EPA, and additional claims remain pending in the U.S. District Court for the Northern District of Alabama. On June 25, 2015, the U.S. Department of Justice filed a joint stipulation between Alabama Power, the EPA, and the U.S. Department of Justice proposing to modify the 2006 consent decree to resolve all remaining claims for relief alleged in the case against Alabama Power. If approved by the U.S. District Court for the Northern District of Alabama, Alabama Power will, without admitting liability, operate subject to emission rates and a cap on certain units and requirements to use only natural gas at certain units, including a unit co-owned by Mississippi Power; retire certain units at Plants Gorgas and Barry; pay a $100,000 civil penalty; and invest $1.5 million in electric transportation infrastructure projects over three years.
The ultimate outcome of these matters cannot be determined at this time.
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 properties.affected sites. The traditional electric operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.
Georgia Power's environmental remediation liability as of June 30, 20152016 was $40$23 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The partiesPRPs at the Brunswick site have completed thea removal of wastes from the Brunswick siteaction 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 cleanupresponse 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 claimsthat PRP) for recoverypaying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site, including costs associated with implementation of natural resource damages at this site or for the assessmentconsent decree. Assessment and potential cleanup of other sites are anticipated.
Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.
In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for the Eastern District of North Carolina Western Division ruled that Georgia Power has no liability in the private action and, on March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. Therefore, the private action is now concluded.
The ultimate outcome of these remaining 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. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47$46 million as of June 30, 2015.2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power 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.
In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.3 million as of June 30, 2015 and is expected to be recovered through the ECO Plan.
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 Georgia Power,and Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.
Nuclear Fuel Disposal Cost Litigation
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.
In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of June 30, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
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 Southern Company and Mississippi Power under "Integrated"Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and "Integrated Coal Gasification Combined Cycle"Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
On March 31, 2015,2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgofor an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base.tariff. The settlement agreement, which was accepted by the FERC, oneffective for services rendered beginning May 13, 2015,1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. 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 December 2015 Mississippi PSC order authorizing rates providing recovery of assets previously placed in service (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 36 months, (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 was effective April 1, 2015.AFUDC. The additional resulting AFUDC is projectedestimated to be approximately $11 million annually, of which $8 million relatesthrough the Kemper IGCC's projected in-service date of October 31, 2016.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $23 million compared to $24 million at December 31, 2015. See Note 3 to the Kemper IGCC. In addition, a settlement agreement entered intofinancial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portionItem 8 of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015.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 on June 30,in 2014, which included continued reliance on the energy auction as tailored mitigation. OnIn April 27, 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. To retain market-based rate authority, theThe 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
for rehearing onin May 27, 2015 and onin June 26, 2015 filed their response with the FERC. The ultimate outcome of this matter 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 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 recovery balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | | | |
| Regulatory Clause |
| Balance Sheet Line Item | June 30, 2015 |
| December 31, 2014 |
|
|
| (in millions) |
Rate CNP Compliance – Under* |
| Deferred under recovered regulatory clause revenues | $ | 25 |
|
| $ | 2 |
|
| | | Under recovered regulatory clause revenues, current | 29 |
| | 47 |
|
| Rate CNP PPA – Under |
| Deferred under recovered regulatory clause revenues | 72 |
|
| 29 |
|
| | | Under recovered regulatory clause revenues, current | — |
| | 27 |
|
| Retail Energy Cost Recovery – Over |
| Deferred over recovered regulatory clause revenues | 72 |
|
| 47 |
|
| Natural Disaster Reserve |
| Other regulatory liabilities, deferred | 81 |
|
| 84 |
|
|
| | | | | | | | |
| Regulatory Clause | Balance Sheet Line Item | June 30,
2016 |
| December 31, 2015 |
|
| (in millions) |
| Rate CNP Compliance | Under recovered regulatory clause revenues | $ | 7 |
| | $ | 43 |
|
| | Deferred under recovered regulatory clause revenues | 21 |
| | — |
|
| Rate CNP PPA | Deferred under recovered regulatory clause revenues | 115 |
|
| 99 |
|
| Retail Energy Cost Recovery | Other regulatory liabilities, current | 75 |
|
| 238 |
|
| Deferred over recovered regulatory clause revenues | 102 |
|
| — |
|
| Natural Disaster Reserve | Other regulatory liabilities, deferred | 72 |
|
| 75 |
|
* Formerly Known As Rate CNP 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 May 2016 and July 2016, respectively.
Georgia Power
Rate CNPPlans
See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of AlabamaGeorgia Power under "Retail Regulatory Matters – Georgia Power – Rate CNP"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 separate fuel cost recovery tariffs. See "Fuel Cost Recovery" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and " – Non-Environmental Federal Mandated Costs Accounting Order"Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Alabama Power's developmentfuel cost recovery and the NCCR tariff, respectively.
Pursuant to the terms and conditions of a revised cost recovery mechanismsettlement 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 normal purchases and normal sales (NPNS) exception for wind PPAs.
On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $30 million of non-environmental compliance costs during the first six months of 2015 andUtilities; thereafter, all merger savings will be limited to recovery of $50 millionretained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under recovered position for Rate CNP Compliance during 2015.Merger.
In April 2015, the FASB proposed new accounting guidance to allow the NPNS exception for physical forward transactions in nodal energy markets, consistent with the manner in which Alabama Power currently accounts for its two wind PPAs. On July 9, 2015, the FASB ratified the consensus reached by the Emerging Issues Task Force to allow the exception in such cases and voted to issue a final accounting standard.
Environmental Accounting Order
In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Subject to the final approval of the New Source Review stipulation, Alabama Power will also
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
retire Plant Barry Unit 3 (225 MWs) which is currently unavailable for generation. See "Environmental Matters – New Source Review Actions" herein for additional information regarding the NSR actions.
In accordance with an accounting order from the Alabama PSC, Alabama Power transferred the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's or Alabama Power's financial statements.
Georgia Power
Integrated Resource Plan
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans"Plan" and "Retail Regulatory Matters – Integrated Resource Plans,Plan," respectively, in Item 8 of the Form 10-K for additional information.information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).
ToOn 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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.
Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with the April 16, 2015 effective date of the MATS rule,existing government-imposed environmental mandates, subject to limits on expenditures for Plant Branch UnitsMcIntosh Unit 1 3, and 4 (1,266 MWs), Plant YatesHammond Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at4.
The Georgia PSC approved reclassification of the remaining net book value of Plant Mitchell Unit 3 (155 MWs) and its decertificationcosts 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. 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 requesteddeferred for consideration in connectionGeorgia Power's 2019 general base rate case.
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 triennial Integrated Resource Plannuclear option at a future generation site in 2016.Stewart County, Georgia. The switch to natural gas astiming of cost recovery will be determined by the primary fuel is completeGeorgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at Plant Yates Units 7 and 6 and the units were returned to service on May 4, 2015 and June 27, 2015, respectively.this time.
Fuel Cost Recovery
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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 June 30, 20152016 and December 31, 2014,2015, Georgia Power's underover recovered fuel balance totaled $106$164 million and $199$116 million, respectively. For June 30, 2015respectively, and December 31, 2014, the balance is included in current assets and current assetsliabilities and other deferred charges and assets, respectively,liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. 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 expectsis currently scheduled to file its next fuel case in September 2015. The ultimate outcome of this matter cannot be determined at this time.case by February 28, 2017.
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.
Nuclear Construction
See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and pending litigation.the Contractor Settlement Agreement (as defined below).
In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. 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 that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims isguarantees, subject to a cap. 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.)WECTEC under the Vogtle 3 and 4 Agreement arewere originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (a(which is now a subsidiary of Chicago Bridge & Iron Company, N.V.)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 certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, 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 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 NRC issued an Early Site Permit and Limited Work Authorization which allowed limited workGeorgia PSC voted to begin oncertify construction of Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. 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 are expected as construction proceeds.
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million in 2008 dollars (approximately $591 million in 2015 dollars).The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor subsequently asserted estimated minimum damages related to the amended counterclaim (based on Georgia Power's ownership interest) of approximately $113 million in 2014 dollars (approximately $118 million in 2015 dollars).In June 2015, the Contractor updated its estimated damages under the initial complaint and the amended counterclaim to an aggregate (based on Georgia Power's ownership interest) of approximately $714 million (in 2015 dollars). The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 certified 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's eighth VCM report filed in 2013Power 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) entered into bybetween Georgia Power and the Georgia PSC staffStaff (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. The
On April 15, 2015, the Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.
On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).
Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistentissued a procedural order in connection with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.
On February 27, 2015, Georgia Power filed its twelfth VCM report, with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated owner'sVogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion.
Georgia Power will continue Pursuant to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.
On April 15, 2015, the Georgia PSC issued aPSC's procedural order in connection with the twelfth VCM report. Pursuant to this 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. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.
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 for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; 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 $250 million had been paid as of June 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.
On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance 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-service capital cost and schedule are reasonable. The Staff is conducting a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement, and is authorized to engage in related settlement discussions with Georgia Power and any intervenors.
The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.
The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.1 billion had been incurred through June 30, 2016.
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 DCDWestinghouse Design Control Document and the COLs,combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 issues are expected tomatters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in itslabor productivity, fabrication, assembly, delivery, and installation of plant equipment, the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.
AdditionalFuture claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely tocould arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement but alsoand, under the enhanced dispute resolution procedures, may be resolved through litigation.litigation after the completion of nuclear fuel load for both units.
The ultimate outcome of these matters cannot be determined at this time.
Gulf Power
Retail Base Rate Case
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 for additional information.
In December 2013, the Florida PSC approved a settlement agreement that providesauthorized Gulf Power mayto reduce depreciation expense and record a regulatory asset up to $62.5 million betweenfrom January 2014 andthrough June 2017. In any given month, such depreciation expense 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. Gulf Power recognized a $19.6 million reduction in depreciation expense inFor 2014, 2015, and the first six months of 2015.2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.
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 recovery balance of each regulatory clause recovery on the balance sheet follows:
|
| | | | | | | | | | |
| Recovery Clause |
| Balance Sheet Location |
| June 30, 2015 |
| December 31, 2014 |
|
|
|
| (in millions) |
| Fuel Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| $ | 24 |
|
| $ | 40 |
|
| Purchased Power Capacity Recovery – Under |
| Under recovered regulatory clause revenues |
| 2 |
|
| — |
|
| Environmental Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| 7 |
|
| 10 |
|
| Energy Conservation Cost Recovery – Under |
| Under recovered regulatory clause revenues |
| — |
|
| 3 |
|
|
| | | | | | | | |
| Regulatory Clause | Balance Sheet Location | June 30,
2016 |
| December 31, 2015 |
|
| (in millions) |
| Fuel Cost Recovery | Other regulatory liabilities, current | $ | 18 |
|
| $ | 18 |
|
| Purchased Power Capacity Recovery | Under recovered regulatory clause revenues | 4 |
|
| 1 |
|
| Environmental Cost Recovery | Under recovered regulatory clause revenues | 1 |
| | 19 |
|
| Energy Conservation Cost Recovery | Other regulatory liabilities, current | — |
| | 4 |
|
Mississippi Power
2015 Rate CaseEnergy 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 15, 2015 and July 10, 2015, Mississippi Power filed alternative rate proposals related to recovery of Kemper IGCC-related costs with3, 2016, the Mississippi PSC. See "Integrated Coal Gasification Combined Cycle – Rate RecoveryPSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of Kemper IGCC Costs – 2015 Rate Case" herein$2 million in retail revenues for additional information.the year ending December 31, 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 March 17, 2015,April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2014,2015, 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 surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow it more time for review. change in rates.
The ultimate outcome of this matterthese matters cannot be determined at this time.
System Restoration Rider
See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.
On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow it more time for review. The ultimate outcome of this matter cannot be determined at this time.
Environmental Compliance Overview Plan
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" and "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC and information on Plant Watson Units 4 and 5.
In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of June 30, 2015, total project expenditures were $604 million, of which Mississippi Power's portion was $308 million, excluding AFUDC of $27 million.
On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. On February 27, 2015, the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
On April 16, 2015, the assets that supported coal generation at Plant Watson Units 4 and 5 were retired. The remaining net book value of these two units was approximately $32 million excluding the reserve for cost of removal and has been reclassified to other regulatory assets, deferred, on Mississippi Power's Condensed Balance Sheet herein in accordance with an accounting order from the Mississippi PSC. Mississippi Power expects to recover through its rates the remaining book value of the retired assets and certain costs, including unusable inventory, associated with the retirements; however, the ultimate method and timing of recovery will be considered by the Mississippi PSC in future rate proceedings.
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 information regarding Mississippi Power's retail fuel cost recovery.
At June 30, 2015,2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $24$76 million compared to under-recovered retail fuel costs of $2$71 million at December 31, 2014.2015.
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 of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.
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.
On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates. On May 26, 2015 the Mississippi PSC suspended the filing to allow it more time to review. The ultimate outcome of this matter cannot be determined at this time.
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
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. 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 (DOE(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 using natural gas in August 2014 and continues to focus onprogress towards completing the remainder of the Kemper IGCC, including the gasifiergasifiers and the gas clean-up facilities,facilities. The in-service date for which the in-service dateremainder of the Kemper IGCC is currently expected to occur inby October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the first halfrelated lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of 2016. the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Recovery of the Kemper IGCC 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)decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of June 30, 2015, as adjusted for the Court's decision,2016, are as follows:
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Cost Category | 2010 Project Estimate(f) | | Current Estimate | | Actual Costs at June 30, 2015 | 2010 Project Estimate(a) | | Current Cost Estimate(b) | | Actual Costs |
| | (in billions) | (in billions) |
Plant Subject to Cost Cap(a)(e) | $ | 2.40 |
| | $ | 4.96 |
| | $ | 4.51 |
| $ | 2.40 |
| | $ | 5.43 |
| | $ | 5.15 |
|
| 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 |
| | 0.11 |
| | 0.12 |
|
AFUDC(c)(d) | 0.17 | | 0.62 | | 0.52 | 0.17 |
| | 0.72 |
| | 0.66 |
|
Combined Cycle and Related Assets Placed in
Service – Incremental(d)(e) | — |
| | 0.02 |
| | — |
| — |
| | 0.03 |
| | 0.02 |
|
| General Exceptions | 0.05 | | 0.10 | | 0.08 | 0.05 |
| | 0.10 |
| | 0.09 |
|
Deferred Costs(c)(e) | — |
| | 0.19 | | 0.15 | |
Total Kemper IGCC(a)(c) | $ | 2.97 |
| | $ | 6.23 |
| | $ | 5.60 |
| |
Deferred Costs(e) | | — |
| | 0.20 |
| | 0.19 |
|
Additional DOE Grants(f) | | — |
| | (0.14 | ) | | (0.14 | ) |
| Total Kemper IGCC | | $ | 2.97 |
| | $ | 6.68 |
| | $ | 6.32 |
|
| |
| (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 reflect estimated costs through October 31, 2016. |
| |
| (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"Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"Order" herein for additional information. The Current Cost Estimate and the Actual Costs includereflect 100% of the 15% undivided interest incosts of the Kemper IGCC that was previously projected to be purchased by SMEPA. On May 20, 2015, SMEPA notified Mississippi Power of its termination of theasset purchase agreement (APA) and requested the return of a total of $275 million of deposits, which was returned with accrued interest on June 3, 2015.IGCC. See note (e) for additional information. |
| |
(b)(d) | Mississippi Power's original estimate2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate"Rate Recovery of Kemper IGCC Costs.Costs – 2013 MPSC Rate Order." The current estimate includes an approximately $11 million decrease in AFUDC due to a decrease in AFUDC rates resulting from an increase in short-term debt, partially offset by an $8 million increase in AFUDC related toCurrent 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""FERC Matters" herein for additional information. |
| |
(c) | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. |
| |
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. |
| |
| (e) | The 2012 MPSC CPCN Order approved deferral of non-capitalNon-capital Kemper IGCC-related costs incurred during construction were initially deferred as describedregulatory assets. Some of these costs are now included in "Raterates and are being recognized through income; however such costs continue to be included in the Current Cost Estimate and the Actual Costs at June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities.Liabilities" herein for additional information. |
| |
| (f) | The 2010 Project Estimate isOn April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the certificated cost estimate adjusted to include the certificatedestimateDOE for the CO2 pipeline facilitiesKemper IGCC (Additional DOE Grants), which was approved in 2011 by the Mississippi PSC.
are expected to be used to reduce future rate impacts for customers. |
Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2015, $3.422016, $3.59 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 $2.08$2.55 billion), $2$6 million in other property and investments, $58$81 million in fossil fuel stock, $41$46 million in materials and supplies, $198$35 million in other regulatory assets, $16current, $180 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets and $24 million in AROs in the balance sheet, with $1 million previously expensed.sheet.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $23$81 million ($1450 million after tax) in the second quarter 20152016 and $9a total of $134 million ($683 million after tax) for the six months ended June 30, 2016. Since 2012, in the first quarter 2015. These amounts are in addition toaggregate, Mississippi Power has incurred charges totaling $868 millionof $2.55 billion ($536 million1.57 billion after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) as a result of changes in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively.above the cost cap for the Kemper IGCC through June 30, 2016. The increasesincrease to the cost estimate in the first and second quarters of 20152016 primarily reflectedreflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to equipment rework, scopeoperational readiness and challenges in start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the related additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016.refractory lining for the gasifiers. Any further extension of the in-service date beyond October 31, 2016 is currently estimated to result in additional base costs of approximately $25 million to $30$35 million per month, whichwhich includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
and commissioning activities. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any further extension of the in-service date with respect to the Kemper IGCC beyond October 31, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13$14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees which are being deferred as regulatory assets and are estimated to totalof approximately $7$3 million per month. For additional information, see "2015 Rate Case" herein.
Any furtherMississippi 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. Further cost increases and/or extensions of the expected in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality ofdifficulties integrating the systems required for sustained operations, major equipment materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, failure, unforeseen engineering or design problems start-up activities for this first-of-a-kind technology (including major equipment failure and system integration),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 subsequent periods, anyAny further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operationsincome 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 recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on 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 relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 2015 Rate Case and any alternativefuture 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
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
2013 Settlement AgreementMPSC Rate Order
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that among other things, establishedwas 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. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.
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's
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in Mississippi Power's 2013 revision to the proposed rate recovery plan filed with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (2013 Rate Mitigation Plan) as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.
2013 MPSC Rate Order
Consistent with the terms of the 2013 Settlement Agreement, inIn 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. 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 the in-service date.IGCC. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC through the in-service date until directed to do otherwise by the Mississippi PSC.
In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment for costs and revenues associated with the operation of the combined cycle as well as the treatment of revenues collected under the 2013 MPSC Rate Order. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which discontinues the collection of rates under the 2013 MPSC Rate Order and requires the refund of all amounts previously collected.
In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.
2015 Mississippi Supreme Court Decision
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On March 12, 2015, Mississippi Power and the Mississippi PSC each filed motions for rehearing, both of which were denied on June 11, 2015. The Court's ruling remanded the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through June 30, 2015, Mississippi Power had collected $331 million through rates under the 2013 MPSC Rate Order and had accrued $22 million in associated carrying costs. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015. Mississippi Power submitted a2015 and required the fourth quarter 2015 refund plan toof the Mississippi PSC on July 21, 2015, which proposed two alternative refund plans for$342 million collected under the Mississippi PSC's consideration: (1) bill credit2013 MPSC Rate Order, along with check option;associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or (2) check-only option. Hearings on the refund plan are scheduled to be held on August 6, 2015.February 2013 legislation described below.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
2015 Rate Case
As a result of theOn August 13, 2015, Mississippi Supreme Court decision and the Mirror CWIP refund, the 2013 Rate Mitigation Plan is no longer viable. See "2015 Mississippi Supreme Court Decision" herein for additional information. On May 15, 2015, Mississippi Power sought alternate rate recovery and filed a rate case (2015 Rate Case) with the Mississippi PSC. This filing included three alternative rate proposals requesting an increase in retail rates and charges in connection with the Kemper IGCC: (i) a traditional rate case, (ii) a rate mitigation plan fixing rates through 2017 (RMP 2017), and (iii) a rate mitigation plan fixing rates through 2019 (RMP 2019). Under the traditional proposal, rates would increase above May 2015 levels by approximately 11.8%, or $114 million annually, effective June 1, 2015, and would be projected to increase approximately an additional 12.0%, or $120 million annually, effective June 1, 2016. The traditional proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. RMP 2017 presents revenue requirements calculated consistent with a rate mitigation plan authorized byPSC approved Mississippi state law that would mitigate the Kemper IGCC's initial retail revenue impact over two years (June 1, 2015 through May 31, 2017). Under RMP 2017, rates would increase above May 2015 levels by approximately 2.6%, or $25 million annually, effective June 1, 2015, and approximately an additional 19.0%, or $197 million annually, effective June 1, 2016. This proposal assumes termination of the Mirror CWIP rate and the refund of the Mirror CWIP regulatory liability over the period from May 2015 through May 2017. In light of the Mississippi PSC's July 7, 2015 order, RMP 2019 is no longer viable as originally proposed by Mississippi Power.
On July 10, 2015, Mississippi Power filed a supplemental filing including aPower's request for interim rates, (the Supplemental Notice) with the Mississippi PSC in response to the July 7, 2015 order of the Mississippi PSC. The Supplemental Notice presentswhich presented an additional alternative rate proposal (In-Service Asset Proposal) for consideration by the Mississippi PSC. The In-Service Asset Proposal is based upon the test period of June 2015 to May 2016, is designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs, and iscosts. The interim rates were designed to collect approximately $159 million annually. The Supplemental Notice requests thatannually and became effective with the first billing cycle in September 2015, subject to refund and certain other conditions.
On December 3, 2015, the Mississippi PSC issued the In-Service Asset Proposal be implemented immediately as interim rates, subject to refund, until such time asRate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi PSC renders a final decision on the In-Service Asset Proposal and requests that the Mississippi PSC establish a scheduling order for consideration of permanent rates underPublic Utilities Staff (MPUS) regarding the In-Service Asset Proposal. Evidentiary hearingsThe In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on the interim rate relief are scheduled to be heldMississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on August 6, 2015.
common equity, and actual embedded interest costs. The revenue requirements set forthIn-Service Asset Rate Order also included a prudence finding of all costs in the alternative rate proposals excludestipulated 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. See "Termination of Proposed Sale of Undivided InterestMississippi Power continues to SMEPA" herein for additional information.evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.
If the Mississippi PSC does not act on the Supplemental Notice or the 2015 Rate Case within 120 daysWith implementation of the Supplemental Noticenew 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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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.
Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to put onerequest recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.
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 three viable alternative rate proposals into effect as temporary rates under bondcertificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and subjectaccrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to refund pursuant to Mississippi state law.utilize alternate financing through securitization or the February 2013 legislation.
Mississippi Power also expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 20152016 of $6.23$6.68 billion, Mississippi Power anticipates that it will incur additional costs afterexpenses in excess of current rates associated with operating the Kemper IGCC in-service dateafter it is placed in service until the Kemper IGCC cost recovery approach is finalized.finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.
Prudence Reviews
The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues andcosts. Mississippi Power is working to reach a mutually acceptable resolution. On July 10, 2015, Mississippi Power submitted the Supplemental Notice to the Mississippi PSC. The Supplemental
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Notice requests that the Mississippi PSC establish a scheduling order for review of the In-Service Asset Proposal. Mississippi Power expectswill seek approval from the Mississippi PSC to address the In-Service Asset Proposal before the end of 2015, although Mississippi Power believes that such a prudence finding is not requireddefer these costs for interimfuture rate reliefrecovery to be granted.determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "2015 Mississippi Supreme Court Decision""Regulatory Assets and "2015 Rate Case" hereinLiabilities" below 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 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 June 30, 2015,2016, the regulatory asset balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC was $198 million. The projected balance at March 31, 2016 is estimated to total approximately $276 million.totaled $101 million as of June 30, 2016. The amortization period for any such costs approved for recovery remains subjectthese assets is expected to approvalbe determined by the Mississippi PSC.PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.
See "2015 Mississippi Supreme Court Decision""2013 MPSC Rate Order" herein for additional information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 million. See "2015 Rate Case" herein for additional information.
Lignite Mine and CO2 Pipeline Facilities
In conjunction with the Kemper IGCC, Mississippi Power will own 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 has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC, (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury willwould purchase 70% of the CO2 captured from the Kemper IGCC and Treetop willwould purchase 30% of the CO2 captured from the Kemper IGCC. The agreementsOn 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 Treetop provide termination rights asif Mississippi Power has not satisfied its contractual obligation to deliver captured CO2 by May 11, 2015. Since May 11, 2015,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 has been engaged in ongoing discussions with its off-takers regarding the status ofis not able to enter into other similar contractual arrangements or otherwise sequester the CO2delivery produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.
The ultimate outcome of these matters cannot be determined at this time.
Litigation
On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, 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 as well as other issuesof 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 respective agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreedKemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to amend certain provisions of their agreement that do notprevent any Kemper IGCC costs from being charged to customers through electric rates.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
affect pricing or minimum purchase quantities. Any termination or material modificationOn 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 and Mississippi Power believe these agreementslegal challenges have no merit; however, an adverse outcome in these proceedings could result in a material reduction in future chemical product sales revenuesimpact Southern Company's results of operations, financial condition, and liquidity and could have a material financial impact on Mississippi Power to the extentPower's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power is not able to enter into other similar contractual arrangements.
Thewill vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.
Termination of Proposed Sale of Undivided Interest to SMEPA
In 2010 and as amended in 2012, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, SMEPA notified Mississippi Power of its termination of the APA between Mississippi Power and SMEPA. Mississippi Power previously received a total of $275 million of deposits from SMEPA that were required to be returned to SMEPA with interest in connection with the termination of the APA. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to SMEPA. Subsequently, Mississippi Power issued an 18-month promissory note in the aggregate principal amount of approximately $301 million to Southern Company.
Investment Tax Credits
The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through June 30, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $242 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. The ultimate outcome of this matter cannot be determined at this time.
Section 174 Research and Experimental Deduction
Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. In May 2015, Southern Company amended its 2008 through 2013 federal income tax returns to include deductions for Kemper IGCC-related R&E expenditures. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $390 million as of June 30, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional information. The ultimate outcome of this tax matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| |
| (C) | FAIR VALUE MEASUREMENTS |
As of June 30, 2015,2016, assets and liabilities measured at fair value on a recurring basis during the period, together with thetheir associated level of the fair value hierarchy, were as follows:
| | | | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| As of June 30, 2015: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | |
| As of June 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) | (in millions) |
| Southern Company | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | 5 |
| $ | — |
| | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
|
| Interest rate derivatives | | — |
| | 11 |
| | — |
| | 11 |
| — |
| | 27 |
| | — |
| | — |
| | 27 |
|
Nuclear decommissioning trusts(a) | | 677 |
| | 887 |
| | 7 |
| | 1,571 |
| 642 |
| | 917 |
| | — |
| | 18 |
| | 1,577 |
|
| Cash equivalents | | 533 |
| | — |
| | — |
| | 533 |
| 1,014 |
| | — |
| | — |
| | — |
| | 1,014 |
|
| Other investments | | 9 |
| | — |
| | 1 |
| | 10 |
| 9 |
| | — |
| | 1 |
| | — |
| | 10 |
|
| Total | | $ | 1,219 |
| | $ | 903 |
| | $ | 8 |
| | $ | 2,130 |
| $ | 1,665 |
| | $ | 980 |
| | $ | 1 |
| | $ | 18 |
| | $ | 2,664 |
|
| Liabilities: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 180 |
| | $ | — |
| | $ | 180 |
| $ | — |
| | $ | 110 |
| | $ | — |
| | $ | — |
| | $ | 110 |
|
| Interest rate derivatives | | — |
| | 14 |
| | — |
| | 14 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Foreign currency derivatives | | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Total | | $ | — |
| | $ | 194 |
| | $ | — |
| | $ | 194 |
| $ | — |
| | $ | 155 |
| | $ | — |
| | $ | — |
| | $ | 155 |
|
| | | | | | | | | | | | | | | | | | |
| Alabama Power | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
| $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
Nuclear decommissioning trusts(b) | | | | | | | | | | | | | | | | |
|
|
| Domestic equity | | 381 |
| | 78 |
| | — |
| | 459 |
| 363 |
| | 67 |
| | — |
| | — |
| | 430 |
|
| Foreign equity | | 51 |
| | 50 |
| | — |
| | 101 |
| 46 |
| | 47 |
| | — |
| | — |
| | 93 |
|
| U.S. Treasury and government agency securities | | — |
| | 36 |
| | — |
| | 36 |
| — |
| | 24 |
| | — |
| | — |
| | 24 |
|
| Corporate bonds | | 10 |
| | 121 |
| | — |
| | 131 |
| 21 |
| | 142 |
| | — |
| | — |
| | 163 |
|
| Mortgage and asset backed securities | | — |
| | 17 |
| | — |
| | 17 |
| — |
| | 22 |
| | — |
| | — |
| | 22 |
|
| Private Equity | | — |
| | — |
| | — |
| | 18 |
| | 18 |
|
| Other | | — |
| | 6 |
| | 7 |
| | 13 |
| — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Cash equivalents | | 81 |
| | — |
| | — |
| | 81 |
| 210 |
| | — |
| | — |
| | — |
| | 210 |
|
| Total | | $ | 523 |
| | $ | 310 |
| | $ | 7 |
| | $ | 840 |
| $ | 640 |
| | $ | 320 |
| | $ | — |
| | $ | 18 |
| | $ | 978 |
|
| Liabilities: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 48 |
| | $ | — |
| | $ | 48 |
| $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| Interest rate derivatives | | — |
| | 7 |
| | — |
| | 7 |
| |
| Total | | $ | — |
| | $ | 55 |
| | $ | — |
| | $ | 55 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | | | Fair Value Measurements Using | | | Fair Value Measurements Using | | |
| As of June 30, 2015: | | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total | |
| As of June 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) | (in millions) |
| Georgia Power | | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
| $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| Interest rate derivatives | | — |
| | 5 |
| | — |
| | 5 |
| — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Nuclear decommissioning trusts(b) (c) | | | | | | | | | | | | | | | | | |
| Domestic equity | | 182 |
| | 1 |
| | — |
| | 183 |
| 187 |
| | 1 |
| | — |
| | — |
| | 188 |
|
| Foreign equity | | — |
| | 125 |
| | — |
| | 125 |
| — |
| | 116 |
| | — |
| | — |
| | 116 |
|
| U.S. Treasury and government agency securities | | — |
| | 95 |
| | — |
| | 95 |
| — |
| | 109 |
| | — |
| | — |
| | 109 |
|
| Municipal bonds | | — |
| | 78 |
| | — |
| | 78 |
| — |
| | 57 |
| | — |
| | — |
| | 57 |
|
| Corporate bonds | | — |
| | 169 |
| | — |
| | 169 |
| — |
| | 159 |
| | — |
| | — |
| | 159 |
|
| Mortgage and asset backed securities | | — |
| | 108 |
| | — |
| | 108 |
| — |
| | 159 |
| | — |
| | — |
| | 159 |
|
| Other | | 53 |
| | 3 |
| | — |
| | 56 |
| 25 |
| | 6 |
| | — |
| | — |
| | 31 |
|
| Cash equivalents | | 90 |
| | — |
| | — |
| | — |
| | 90 |
|
| Total | | $ | 302 |
| | $ | 636 |
| | $ | — |
| | $ | — |
| | $ | 938 |
|
| Liabilities: | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| | | | | | | | | | | |
| Gulf Power | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Cash equivalents | | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
| Total | | $ | 235 |
| | $ | 587 |
| | $ | — |
| | $ | 822 |
| $ | 20 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| Liabilities: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 17 |
| | $ | — |
| | $ | 17 |
| $ | — |
| | $ | 55 |
| | $ | — |
| | $ | — |
| | $ | 55 |
|
| Interest rate derivatives | | — |
| | 4 |
| | — |
| | 4 |
| — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Total | | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | 21 |
| $ | — |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | 62 |
|
| | | | | | | | | | | | | | | | | | |
| Gulf Power | | | | | | | | | |
| Mississippi Power | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Cash equivalents | | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 18 |
| 102 |
| | — |
| | — |
| | — |
| | 102 |
|
| Total | | $ | 102 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 103 |
|
| Liabilities: | | | | | | | | | | | | | | | | | |
| Energy-related derivatives | | — |
| | 74 |
| | — |
| | 74 |
| $ | — |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
| | | | | | | | | | |
| Mississippi Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | | $ | 182 |
| | $ | — |
| | $ | — |
| | $ | 182 |
| |
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | | — |
| | 41 |
| | — |
| | 41 |
| |
| | | | | | | | | | |
| Southern Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Cash equivalents | | $ | 206 |
| | $ | — |
| | $ | — |
| | $ | 206 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | |
| As of June 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 Power | | | | | | | | | |
| Assets: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
| Cash equivalents | 449 |
| | — |
| | — |
| | — |
| | 449 |
|
| Total | $ | 449 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | 457 |
|
| Liabilities: | | | | | | | | | |
| Energy-related derivatives | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Foreign currency derivatives | — |
| | 38 |
| | — |
| | — |
| | 38 |
|
| Total | $ | — |
| | $ | 43 |
| | $ | — |
| | $ | — |
| | $ | 43 |
|
| |
| (a) | For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table. |
| |
| (b) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. |
| |
| (c) | Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2015,2016, approximately $39$46 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. |
TableSouthern 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 Contentsthe funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $28 million and $48 million, respectively, for the three and six months ended June 30, 2016, and decreased by $1 million and increased by $31 million, respectively, for the three and six months ended June 30, 2015. Alabama Power recorded an increase in fair value of $29 million and $40 million, respectively, for the three and six months ended June 30, 2016 and $5 million and $19 million, respectively, for the three and six months ended June 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and an increase of $8 million, respectively, for the three and six months ended June 30, 2016 and a decrease in fair value of $6 million and an increase in fair value of $12 million, respectively, for the three and six months ended June 30, 2015 as a change in its regulatory asset related to its AROs.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Valuation Methodologies
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products that are valued using theobservable market approach. Inputs fordata and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include LIBOR interest rates, interest rate futures contracts,the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
data and valuations of similar instruments. See Note (H) herein 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' judgment,judgments, are also obtained when available.
Investments See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the natureItem 8 of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.Form 10-K for additional information.
"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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of June 30, 2015,2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent), as a practical expedient, as well as the nature and risks of those investments, were as follows:
|
| | | | | | | | | | |
| As of June 30, 2015: | | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | | (in millions) | | | | | | |
| Southern Company | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Foreign equity funds | | $ | 125 |
| | None | | Monthly | | 5 days |
| Equity - commingled funds | | 50 |
| | None | | Daily | | Daily |
| Debt - commingled funds | | 16 |
| | None | | Daily | | 5 days |
| Other - commingled funds | | 3 |
| | None | | Daily | | Not applicable |
| Other - money market funds | | 53 |
| | None | | Daily | | Not applicable |
| Trust-owned life insurance | | 117 |
| | None | | Daily | | 15 days |
| Cash equivalents: | | | | | | | | |
| Money market funds | | 533 |
| | None | | Daily | | Not applicable |
| Alabama Power | | | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Equity - commingled funds | | $ | 50 |
| | None | | Daily | | Daily |
| Debt - commingled funds | | 16 |
| | None | | Daily | | 5 days |
| Trust-owned life insurance | | 117 |
| | None | | Daily | | 15 days |
| Cash equivalents: | | | | | | | | |
| Money market funds | | 81 |
| | None | | Daily | | Not applicable |
| Georgia Power | | | | | | | | |
| Nuclear decommissioning trusts: | | | | | | | | |
| Foreign equity funds | | $ | 125 |
| | None | | Monthly | | 5 days |
| Other - commingled funds | | 3 |
| | None | | Daily | | Not applicable |
| Other - money market funds | | 53 |
| | None | | Daily | | Not applicable |
| Gulf Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 18 |
| | None | | Daily | | Not applicable |
| Mississippi Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 182 |
| | None | | Daily | | Not applicable |
| Southern Power | | | | | | | | |
| Cash equivalents: | | | | | | | | |
| Money market funds | | $ | 206 |
| | None | | Daily | | Not applicable |
|
| | | | | | | | | | | |
| As of June 30, 2016: | Fair Value | | Unfunded Commitments | | Redemption Frequency | | Redemption Notice Period |
| | (in millions) | | | | |
| Southern Company | $ | 18 |
| | $ | 28 |
| | Not Applicable | | Not Applicable |
| Alabama Power | $ | 18 |
| | $ | 28 |
| | Not Applicable | | Not Applicable |
The NRC requires licensees of commissioned nuclear power reactors to establishPrivate equity funds include a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarilyfund-of-funds that invests in high-quality private equity funds across several market sectors, a diversified portfolio of equity securities of foreign companies, including thosefund that invests in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts (including American depositary receipts, European depositary receipts,assets, and global depositary receipts), and rights and warrantsa fund that acquires companies to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreigncreate resale value. Private equity fund, then the foreign equity fund's board may refuse to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.
The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Alabama Power's nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not ownhave redemption rights. Distributions from these funds will be received as the underlying investments but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and six months ended June 30, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $44 million and $109 million, respectively, at Southern Company. For the three and six months ended June 30, 2015, Alabama Power recorded an increase in fair value of $50 million and $97 million, respectively, as an increase in regulatory liabilities. For the three and six months ended June 30, 2015, Georgia Power recorded a decrease in fair value of $6 million and an increase of $12 million, respectively, as a reduction of its regulatory asset related to its ARO.
The money market funds are short-term investments of excess funds inliquidated. Liquidations are expected to occur at various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated bytimes over the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.next ten years.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
As of June 30, 2015,2016, 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 | | $ | 26,156 |
| | $ | 26,973 |
| $ | 37,953 |
| | $ | 40,992 |
|
| Alabama Power | | $ | 7,295 |
| | $ | 7,621 |
| $ | 7,090 |
| | $ | 7,940 |
|
| Georgia Power | | $ | 10,379 |
| | $ | 10,767 |
| $ | 10,603 |
| | $ | 11,881 |
|
| Gulf Power | | $ | 1,370 |
| | $ | 1,438 |
| $ | 1,182 |
| | $ | 1,275 |
|
| Mississippi Power | | $ | 2,275 |
| | $ | 2,246 |
| $ | 2,983 |
| | $ | 2,967 |
|
| Southern Power | | $ | 2,262 |
| | $ | 2,302 |
| $ | 4,332 |
| | $ | 4,523 |
|
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.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 June 30, 2015 |
| Three Months Ended June 30, 2014 | | Six Months Ended June 30, 2015 | | Six Months Ended June 30, 2014 | Three Months Ended June 30, 2016 |
| Three Months Ended June 30, 2015 | | Six Months Ended June 30, 2016 | | Six Months Ended June 30, 2015 |
| | | (in millions) | (in millions) |
| As reported shares | | 909 |
| | 895 |
| | 910 |
| | 892 |
| 934 |
| | 909 |
| | 925 |
| | 910 |
|
| Effect of options and performance share award units | | 3 |
| | 4 |
| | 4 |
| | 4 |
| 6 |
| | 3 |
| | 6 |
| | 4 |
|
| Diluted shares | | 912 |
| | 899 |
| | 914 |
| | 896 |
| 940 |
| | 912 |
| | 931 |
| | 914 |
|
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 andsix months ended June 30, 2016, respectively, and were 15 million and 1 million for the three and six months ended June 30, 2015, respectively, and were 8 million and 17 million for the three and six months ended June 30, 2014, 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 Interest(*) | | Issued | | Treasury | | Noncontrolling Interests(*) | |
| | (in thousands) | | (in millions) | (in thousands) | | (in millions) |
| Balance at December 31, 2015 | | 915,073 |
| | (3,352 | ) | | $ | 20,592 |
| | $ | 609 |
| | $ | 781 |
| | $ | 21,982 |
|
| Consolidated net income attributable to Southern Company | | — |
| | — |
| | 1,097 |
| | — |
| | — |
| | 1,097 |
|
| Other comprehensive income (loss) | | — |
| | — |
| | (117 | ) | | — |
| | — |
| | (117 | ) |
| Stock issued | | 27,297 |
| | 2,599 |
| | 1,383 |
| | — |
| | — |
| | 1,383 |
|
| Stock-based compensation | | — |
| | — |
| | 82 |
| | — |
| | — |
| | 82 |
|
| Cash dividends on common stock | | — |
| | — |
| | (1,023 | ) | | — |
| | — |
| | (1,023 | ) |
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 169 |
| | 169 |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) |
| Purchase of membership interests from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (129 | ) | | (129 | ) |
| Net income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Other | | — |
| | (19 | ) | | 1 |
| | — |
| | — |
| | 1 |
|
| Balance at June 30, 2016 | | 942,370 |
| | (772 | ) | | $ | 22,015 |
| | $ | 609 |
| | $ | 822 |
| | $ | 23,446 |
|
| | | | | | | | | | | | | |
| Balance at December 31, 2014 | 908,502 |
| | (725 | ) | | $ | 19,949 |
| | $ | 756 |
| | $ | 221 |
| | $ | 20,926 |
| 908,502 |
| | (725 | ) | | $ | 19,949 |
| | $ | 756 |
| | $ | 221 |
| | $ | 20,926 |
|
| Net income after dividends on preferred and preference stock | — |
| | — |
| | 1,138 |
| | — |
| | — |
| | 1,138 |
| |
| Consolidated net income attributable to Southern Company | | — |
| | — |
| | 1,138 |
| | — |
| | — |
| | 1,138 |
|
| Other comprehensive income (loss) | — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
| — |
| | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Stock issued | 3,222 |
| | — |
| | 117 |
| | — |
| | — |
| | 117 |
| 3,222 |
| | — |
| | 117 |
| | — |
| | — |
| | 117 |
|
| Stock-based compensation | — |
| | — |
| | 66 |
| | — |
| | — |
| | 66 |
| — |
| | — |
| | 66 |
| | — |
| | — |
| | 66 |
|
| Stock repurchased, at cost | — |
| | (2,599 | ) | | (115 | ) | | — |
| | — |
| | (115 | ) | — |
| | (2,599 | ) | | (115 | ) | | — |
| | — |
| | (115 | ) |
| Cash dividends on common stock | — |
| | — |
| | (972 | ) | | — |
| | — |
| | (972 | ) | — |
| | — |
| | (972 | ) | | — |
| | — |
| | (972 | ) |
| Preference stock redemption | — |
| | — |
| | — |
| | (150 | ) | | — |
| | (150 | ) | — |
| | — |
| | — |
| | (150 | ) | | — |
| | (150 | ) |
| Contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 135 |
| | 135 |
| |
| Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | (5 | ) | | (5 | ) | |
| Net income attributable to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
| |
| Contributions from noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 135 |
| | 135 |
|
| Distributions to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | (5 | ) | | (5 | ) |
| Net income attributable to noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
|
| Other | — |
| | 25 |
| | (8 | ) | | 3 |
| | — |
| | (5 | ) | — |
| | 25 |
| | (8 | ) | | 3 |
| | — |
| | (5 | ) |
| Balance at June 30, 2015 | 911,724 |
| | (3,299 | ) | | $ | 20,182 |
| | $ | 609 |
| | $ | 355 |
| | $ | 21,146 |
| 911,724 |
| | (3,299 | ) | | $ | 20,182 |
| | $ | 609 |
| | $ | 355 |
| | $ | 21,146 |
|
| | | | | | | | | | | | | |
| Balance at December 31, 2013 | 892,733 |
| | (5,647 | ) | | $ | 19,008 |
| | $ | 756 |
| | $ | — |
| | $ | 19,764 |
| |
| Net income after dividends on preferred and preference stock | — |
| | — |
| | 962 |
| | — |
| | — |
| | 962 |
| |
| Other comprehensive income (loss) | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| |
| Treasury stock re-issued | — |
| | 4,739 |
| | 216 |
| | — |
| | — |
| | 216 |
| |
| Stock issued | 3,898 |
| | — |
| | 161 |
| | — |
| | — |
| | 161 |
| |
| Stock repurchased, at cost | — |
| | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) | |
| Cash dividends on common stock | — |
| | — |
| | (920 | ) | | — |
| | — |
| | (920 | ) | |
| Other | — |
| | (27 | ) | | — |
| | — |
| | — |
| | — |
| |
| Balance at June 30, 2014 | 896,631 |
| | (935 | ) | | $ | 19,426 |
| | $ | 756 |
| | $ | — |
| | $ | 20,182 |
| |
| |
| (*) | Primarily related to Southern Power Company. |
(*) Primarily related to Southern Power Company.
Stock Repurchased
On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through June 30, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.
Bank Credit Arrangements
Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 20152016 was approximately $1.9 billion (comprised of approximately $810$890 million at Alabama Power, $970$868 million at Georgia Power, $69$82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2015,2016, the traditional electric operating companies had approximately $368$320 million (comprised of approximately $200$87 million at Alabama Power, $122$212 million at Georgia Power, and $46$21 million at Gulf 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 for additional information. See "Financing Activities"and "Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of June 30, 2015:2016:
| | | | | Expires | | | | Executable Term Loans | | Due Within One Year | Expires | | | | Executable Term Loans | | Due Within One Year |
| Company | | 2015 |
| | 2016 |
| | 2017 | | 2018 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out | 2016 |
| 2017 | 2018 | 2020 | | Total | | Unused | | One Year | | Two Years | | Term Out | | No Term Out |
| | | (in millions) | | (in millions) | | (in millions) | | (in millions) | (in millions) | | (in millions) | | (in millions) | | (in millions) |
Southern Company | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | 1,000 |
| | $ | 1,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| $ | 1,000 |
| $ | 1,250 |
| | $ | 2,250 |
| | $ | 2,250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | | 154 |
| | 124 |
| | — |
| | 1,030 |
| | 1,308 |
| | 1,307 |
| | 58 |
| | — |
| | 58 |
| | 170 |
| 3 |
| 32 |
| 500 |
| 800 |
| | 1,335 |
| | 1,335 |
| | — |
| | — |
| | — |
| | 35 |
|
| Georgia Power | | — |
| | 150 |
| | — |
| | 1,600 |
| | 1,750 |
| | 1,737 |
| | — |
| | — |
| | — |
| | 150 |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,732 |
| | — |
| | — |
| | — |
| | — |
|
| Gulf Power | | 20 |
| | 225 |
| | 30 |
| | — |
| | 275 |
| | 275 |
| | 50 |
| | — |
| | 50 |
| | 195 |
| 75 |
| 40 |
| 165 |
| — |
| | 280 |
| | 280 |
| | 45 |
| | — |
| | 45 |
| | 70 |
|
| Mississippi Power | | 40 |
| | 255 |
| | — |
| | — |
| | 295 |
| | 265 |
| | 30 |
| | 40 |
| | 70 |
| | 225 |
| 115 |
| 60 |
| — |
| — |
| | 175 |
| | 150 |
| | — |
| | 15 |
| | 15 |
| | 160 |
|
| Southern Power | | — |
| | — |
| | — |
| | 500 |
| | 500 |
| | 466 |
| | — |
| | — |
| | — |
| | — |
| |
Southern Power Company(b) | | — |
| — |
| — |
| 600 |
| | 600 |
| | 560 |
| | — |
| | — |
| | — |
| | — |
|
| Other | | 25 |
| | 45 |
| | — |
| | — |
| | 70 |
| | 70 |
| | 20 |
| | — |
| | 20 |
| | 50 |
| 25 |
| 45 |
| — |
| 40 |
| | 110 |
| | 80 |
| | 20 |
| | — |
| | 20 |
| | 50 |
|
| Total | | $ | 239 |
| | $ | 799 |
| | $ | 30 |
| | $ | 4,130 |
| | $ | 5,198 |
| | $ | 5,120 |
| | $ | 158 |
| | $ | 40 |
| | $ | 198 |
| | $ | 790 |
| $ | 218 |
| $ | 177 |
| $ | 1,665 |
| $ | 4,440 |
| | $ | 6,500 |
| | $ | 6,387 |
| | $ | 65 |
| | $ | 15 |
| | $ | 80 |
| | $ | 315 |
|
| |
| (a) | On May 24, 2016, the $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated. |
| |
| (b) | Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information. |
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 Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings 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. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of June 30, 2016.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Project | | Maturity Date | | Construction Loan Facility | | Bridge Loan Facility | | Loan Facility Total | | Total Loan Facility Undrawn | | Letter of Credit Facility | | Total Letter of Credit Facility Undrawn |
| | | | | (in millions) |
| Tranquillity | | Earlier of PPA COD or December 31, 2016 | | $ | 86 |
| | $ | 172 |
| | $ | 258 |
| | $ | 19 |
| | $ | 77 |
| | $ | 26 |
|
| Roserock | | Earlier of PPA COD or November 30, 2016 | | 63 |
| | 180 |
| | 243 |
| | 34 |
| | 23 |
| | 16 |
|
| Garland | | Earlier of PPA COD or November 30, 2016 | | 86 |
| | 308 |
| | 394 |
| | 73 |
| | 49 |
| | 23 |
|
| Total | | | | $ | 235 |
| | $ | 660 |
| | $ | 895 |
| | $ | 126 |
| | $ | 149 |
| | $ | 65 |
|
The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.
Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2015:2016:
| | Company(a) | Senior Note Issuances | | Senior Note Redemptions | | Revenue Bond Issuances and Reofferings of Purchased Bonds(b) | | Revenue
Bond
Maturities and
Repurchases | | Other Long-Term Debt Issuances | | Other Long-Term Debt Redemptions and Maturities(c) | 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) | (in millions) |
| Southern Company | $ | 600 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 8,500 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Alabama Power | 975 |
| | 250 |
| | 80 |
| | 134 |
| | — |
| | — |
| 400 |
| | 200 |
| | — |
| | 45 |
| | — |
|
| Georgia Power | — |
| | 125 |
| | 170 |
| | 65 |
| | 600 |
| | 5 |
| 650 |
| | 500 |
| | 4 |
| | 300 |
| | 3 |
|
| Gulf Power | | — |
| | 125 |
| | — |
| | — |
| | — |
|
| Mississippi Power | — |
| | — |
| | — |
| | — |
| | — |
| | 351 |
| — |
| | — |
| | — |
| | 1,100 |
| | 651 |
|
| Southern Power | 650 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 1,241 |
| | — |
| | — |
| | 2 |
| | 4 |
|
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | 9 |
| — |
| | — |
| | — |
| | — |
| | 10 |
|
Elimination(b) | | — |
| | — |
| | — |
| | (200 | ) | | (225 | ) |
| Total | $ | 2,225 |
| | $ | 375 |
| | $ | 250 |
| | $ | 199 |
| | $ | 600 |
| | $ | 365 |
| $ | 10,791 |
| | $ | 825 |
| | $ | 4 |
| | $ | 1,247 |
| | $ | 443 |
|
| |
| (a) | Gulf Power did not issue or redeem any long-term debt during the first six months of 2015. |
| |
(b) | Includes reoffering by Alabama Power of $80 million aggregate principal amount of revenue bonds previously purchased and held by Alabama Power since April 2015 and reofferings by Georgia Power of $104.6 million and $65 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2013 and April 2015, respectively. |
| |
(c) | Includes reductions in capital lease obligations resulting from cash payments under capital leases. |
| |
| (b) | Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements. |
In June 2015, Southern Company issued $600 million aggregate principal amount of Series 2015A 2.750% Senior Notes due June 15, 2020. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.
Alabama Power
In March 2015, Alabama Power issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including Alabama Power's continuous construction program.
In April 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power reoffered these bonds to the public in May 2015.
Also in April 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes were used to redeem in May 2015 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
GeorgiaSouthern Company
In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount 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.
The net proceeds were used to fund a portion of the Merger and related transaction costs and for other general corporate purposes.
Alabama Power
In April 2015, GeorgiaJanuary 2016, Alabama Power purchased and held $65issued $400 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power reoffered these bonds2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to the public in May 2015.
In May 2015, Georgia Power reoffered to the public $104.6repay at maturity $200 million aggregate principal amount of Development AuthorityAlabama Power's Series FF 5.20% Senior Notes due January 15, 2016 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 Burke County (Georgia) Pollution Control Revenue Bonds (GeorgiaMarch 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 Company Plant Vogtle Project), First Series 2013, which had been previously purchased and held by
In March 2016, Georgia Power since 2013.issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. 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 2015,2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $600$300 million. The interest rate applicable to the $600$300 million principal amount is 3.283%2.571% for an interest period that extends to 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. Georgia Power settled $350 million of interest rate swaps related to this borrowing for approximately $6 million, which will be amortized to interest expense over 10 years.
MississippiGulf Power
In April 2015, MississippiMay 2016, Gulf Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in anredeemed $125 million aggregate principal amount of $475 million,its Series 2011A 5.75% Senior Notes due June 1, 2051.
Also in May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. The proceeds of these loans were usedThis short-term loan was for the repayment of term loans in an$100 million aggregate principal amount of $275 million,and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes, including Mississippi Power's ongoing construction program. purposes.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.
In June 2015,January 2016, Mississippi Power issued an 18-montha floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. ThisAs of June 30, 2016, Mississippi Power had borrowed $100 million under this promissory note waswith a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. 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 existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.
On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate principal amount of approximately $301$1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the amount paid by Southern Companyterm loan agreement and has the right to SMEPAborrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to Southern Company's guarantee of the return of SMEPA's deposit in connection with the termination of the APA. See Note (B) under "Integrated Coal Gasification Combined Cycle – Termination of Proposed Sale of Undivided Interest to SMEPA" herein for additional information.this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.
In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.
Southern Power
During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In May 2015,addition, Southern Power's subsidiaries issued $16 million in letters of credit.
In June 2016, Southern Power Company issued $350€600 million aggregate principal amount of Series 2015A 1.500%2016A 1.00% Senior Notes due June 1, 201820, 2022 and $300€500 million aggregate principal amount of Series 2015B 2.375%2016B 1.85% Senior Notes due June 1, 2020.20, 2026. The proceeds were usedwill be allocated to repay a portion of its outstanding short-term indebtedness, for other general corporate purposes, includingrenewable energy generation projects. Southern Power's growth strategyobligations 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 continuous construction program, andprincipal payments. See Note (H) under "Foreign Currency Derivatives" for a portion of the subsequent repayment at maturity of $525 million aggregate principal amount of Southern Power Company's 4.875% Senior Notes on July 15, 2015.additional information.
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015.2016. 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)
Components of the net periodic benefit costs for the three and six months ended June 30, 20152016 and 20142015 were as follows:
| | | Pension Plans | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | | (in millions) | | (in millions) |
| Three Months Ended June 30, 2016 | | | | | | | | | | | |
| Service cost | | | $ | 62 |
| | $ | 15 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | | | 101 |
| | 24 |
| | 34 |
| | 4 |
| | 5 |
|
| Expected return on plan assets | | | (187 | ) | | (46 | ) | | (65 | ) | | (8 | ) | | (8 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | | 3 |
| | — |
| | 2 |
| | 1 |
| | — |
|
| Net (gain)/loss | | | 37 |
| | 10 |
| | 13 |
| | 1 |
| | 1 |
|
| Net cost | | | $ | 16 |
| | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Six Months Ended June 30, 2016 | | | | | | | | | | | |
| Service cost | | | $ | 124 |
| | $ | 29 |
| | $ | 35 |
| | $ | 6 |
| | $ | 6 |
|
| Interest cost | | | 201 |
| | 48 |
| | 68 |
| | 9 |
| | 10 |
|
| Expected return on plan assets | | | (374 | ) | | (92 | ) | | (129 | ) | | (17 | ) | | (17 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | | 7 |
| | 1 |
| | 3 |
| | 1 |
| | — |
|
| Net (gain)/loss | | | 75 |
| | 20 |
| | 27 |
| | 3 |
| | 3 |
|
| Net cost | | | $ | 33 |
| | $ | 6 |
| | $ | 4 |
| | $ | 2 |
| | $ | 2 |
|
| Three Months Ended June 30, 2015 | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 64 |
| | $ | 15 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
| | $ | 64 |
| | $ | 15 |
| | $ | 18 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | | 111 |
| | 27 |
| | 39 |
| | 5 |
| | 6 |
| | 111 |
| | 27 |
| | 39 |
| | 5 |
| | 6 |
|
| Expected return on plan assets | | (181 | ) | | (44 | ) | | (63 | ) | | (8 | ) | | (9 | ) | | (181 | ) | | (44 | ) | | (63 | ) | | (8 | ) | | (9 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 7 |
| | 1 |
| | 2 |
| | — |
| | 1 |
| | 7 |
| | 1 |
| | 2 |
| | — |
| | 1 |
|
| Net (gain)/loss | | 54 |
| | 13 |
| | 19 |
| | 2 |
| | 2 |
| | 54 |
| | 13 |
| | 19 |
| | 2 |
| | 2 |
|
| Net cost | | $ | 55 |
| | $ | 12 |
| | $ | 15 |
| | $ | 2 |
| | $ | 3 |
| | $ | 55 |
| | $ | 12 |
| | $ | 15 |
| | $ | 2 |
| | $ | 3 |
|
| Six Months Ended June 30, 2015 | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 128 |
| | $ | 30 |
| | $ | 36 |
| | $ | 6 |
| | $ | 6 |
| | $ | 128 |
| | $ | 30 |
| | $ | 36 |
| | $ | 6 |
| | $ | 6 |
|
| Interest cost | | 222 |
| | 53 |
| | 77 |
| | 10 |
| | 11 |
| | 222 |
| | 53 |
| | 77 |
| | 10 |
| | 11 |
|
| Expected return on plan assets | | (362 | ) | | (89 | ) | | (126 | ) | | (16 | ) | | (17 | ) | | (362 | ) | | (89 | ) | | (126 | ) | | (16 | ) | | (17 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 13 |
| | 3 |
| | 5 |
| | — |
| | 1 |
| | 13 |
| | 3 |
| | 5 |
| | — |
| | 1 |
|
| Net (gain)/loss | | 108 |
| | 27 |
| | 38 |
| | 5 |
| | 5 |
| | 108 |
| | 27 |
| | 38 |
| | 5 |
| | 5 |
|
| Net cost | | $ | 109 |
| | $ | 24 |
| | $ | 30 |
| | $ | 5 |
| | $ | 6 |
| | $ | 109 |
| | $ | 24 |
| | $ | 30 |
| | $ | 5 |
| | $ | 6 |
|
| Three Months Ended June 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 54 |
| | $ | 12 |
| | $ | 15 |
| | $ | 1 |
| | $ | 2 |
| |
| Interest cost | | 108 |
| | 26 |
| | 38 |
| | 5 |
| | 5 |
| |
| Expected return on plan assets | | (162 | ) | | (42 | ) | | (56 | ) | | (7 | ) | | (7 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 7 |
| | 2 |
| | 2 |
| | 1 |
| | 1 |
| |
| Net (gain)/loss | | 27 |
| | 8 |
| | 10 |
| | 1 |
| | 1 |
| |
| Net cost | | $ | 34 |
| | $ | 6 |
| | $ | 9 |
| | $ | 1 |
| | $ | 2 |
| |
| Six Months Ended June 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 107 |
| | $ | 24 |
| | $ | 31 |
| | $ | 4 |
| | $ | 5 |
| |
| Interest cost | | 217 |
| | 52 |
| | 76 |
| | 10 |
| | 10 |
| |
| Expected return on plan assets | | (323 | ) | | (84 | ) | | (113 | ) | | (14 | ) | | (14 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 13 |
| | 3 |
| | 5 |
| | 1 |
| | 1 |
| |
| Net (gain)/loss | | 55 |
| | 16 |
| | 20 |
| | 2 |
| | 2 |
| |
| Net cost | | $ | 69 |
| | $ | 11 |
| | $ | 19 |
| | $ | 3 |
| | $ | 4 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Postretirement Benefits | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | | (in millions) | | (in millions) |
| Three Months Ended June 30, 2016 | | | | | | | | | | | |
| Service cost | | | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | | | 17 |
| | 4 |
| | 7 |
| | — |
| | 1 |
|
| Expected return on plan assets | | | (14 | ) | | (7 | ) | | (5 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | | | 4 |
| | 1 |
| | 2 |
| | — |
| | — |
|
| Net cost | | | $ | 14 |
| | $ | 1 |
| | $ | 6 |
| | $ | — |
| | $ | 1 |
|
| Six Months Ended June 30, 2016 | | | | | | | | | | | |
| Service cost | | | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
|
| Interest cost | | | 35 |
| | 9 |
| | 15 |
| | 1 |
| | 2 |
|
| Expected return on plan assets | | | (28 | ) | | (13 | ) | | (11 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
|
| Net (gain)/loss | | | 7 |
| | 1 |
| | 4 |
| | — |
| | — |
|
| Net cost | | | $ | 28 |
| | $ | 2 |
| | $ | 12 |
| | $ | 1 |
| | $ | 2 |
|
| Three Months Ended June 30, 2015 | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 5 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 5 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | | 20 |
| | 5 |
| | 9 |
| | 1 |
| | 1 |
| | 20 |
| | 5 |
| | 9 |
| | 1 |
| | 1 |
|
| Expected return on plan assets | | (14 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | (1 | ) | | (14 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | | 4 |
| | 1 |
| | 3 |
| | — |
| | — |
| | 4 |
| | 1 |
| | 3 |
| | — |
| | — |
|
| Net cost | | $ | 16 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | 1 |
| | $ | 16 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | 1 |
|
| Six Months Ended June 30, 2015 | | | | | | | | | | | | | | | | | | | | |
| Service cost | | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | — |
| | $ | 1 |
| | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | — |
| | $ | 1 |
|
| Interest cost | | 39 |
| | 10 |
| | 17 |
| | 2 |
| | 2 |
| | 39 |
| | 10 |
| | 17 |
| | 2 |
| | 2 |
|
| Expected return on plan assets | | (29 | ) | | (13 | ) | | (12 | ) | | (1 | ) | | (1 | ) | | (29 | ) | | (13 | ) | | (12 | ) | | (1 | ) | | (1 | ) |
| Amortization: | | | | | | | | | | | | | | | | | | | | |
| Prior service costs | | 2 |
| | 1 |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
| | — |
| | — |
| | — |
|
| Net (gain)/loss | | 9 |
| | 1 |
| | 6 |
| | — |
| | — |
| | 9 |
| | 1 |
| | 6 |
| | — |
| | — |
|
| Net cost | | $ | 32 |
| | $ | 2 |
| | $ | 14 |
| | $ | 1 |
| | $ | 2 |
| | $ | 32 |
| | $ | 2 |
| | $ | 14 |
| | $ | 1 |
| | $ | 2 |
|
| Three Months Ended June 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 6 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| |
| Interest cost | | 20 |
| | 5 |
| | 9 |
| | 1 |
| | 1 |
| |
| Expected return on plan assets | | (15 | ) | | (7 | ) | | (7 | ) | | (1 | ) | | (1 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 1 |
| | 1 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | | — |
| | — |
| | 1 |
| | — |
| | — |
| |
| Net cost | | $ | 12 |
| | $ | 1 |
| | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| |
| Six Months Ended June 30, 2014 | | | | | | | | | | | |
| Service cost | | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
| |
| Interest cost | | 40 |
| | 10 |
| | 17 |
| | 2 |
| | 2 |
| |
| Expected return on plan assets | | (30 | ) | | (13 | ) | | (13 | ) | | (1 | ) | | (1 | ) | |
| Amortization: | | | | | | | | | | | |
| Prior service costs | | 2 |
| | 2 |
| | — |
| | — |
| | — |
| |
| Net (gain)/loss | | 1 |
| | — |
| | 1 |
| | — |
| | — |
| |
| Net cost | | $ | 24 |
| | $ | 2 |
| | $ | 8 |
| | $ | 2 |
| | $ | 2 |
| |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Current and Deferred Income Taxes
State of Georgia Tax Benefits
During the second quarter 2015, an agreement was reached with the Georgia Department of Revenue that will allow Southern Company to utilize a net operating loss carryforward over a four-year period beginning in 2017. Consequently, Southern Company reversed the related valuation allowance and recognized approximately $24 million in net tax benefits as of June 30, 2015. See Note 5 to the financial statements of Southern Company under "Current and Deferred Income Taxes"each registrant in Item 8 of the Form 10-K for additional tax information.
Southern Power ITCCurrent and Deferred Income Taxes
Tax Credit Carryforwards
Southern Power hadCompany has federal ITC and PTC carryforwards which are expected to result in $428totaling $801 million and $16 million, respectively, at June 30, 2016 (comprised primarily of $784 million and $16 million of federal income tax benefitsITC and PTC carryforwards, respectively, at Southern Power). These ITC and PTC carryforwards increased from $554 million and $1 million, respectively, as of December 31, 2015 (comprised primarily of $551 million and $1 million of ITC and PTC carryforwards, respectively, at Southern Power). Additionally, Southern Company has $208 million of state ITC carryforwards for the state of Georgia as of June 30, 2015,2016, compared to $305$188 million as ofat December 31, 2014. 2015.
The federal ITC carryforwards as of June 30, 2015 expire between 2031 and 2035 and2016 begin expiring in 2034 but are expected to be utilized by the end of 2016.2021. The PTC carryforwards as of June 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2020. The state ITC carryforwards for the state of Georgia as of June 30, 2016 expire between 2020 and 2026 but are expected to be fully utilized by the end of 2022.
Effective Tax Rate
See Note 5Southern 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 30.4% for the six months ended June 30, 2016 compared to 32.9% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and increased tax benefits related to the financial statements of each registrant in Item 8estimated probable losses on Mississippi Power's construction of the Form 10-K forKemper IGCC, partially offset by the impact of additional state income tax information.benefits recognized in 2015.
Mississippi Power
Mississippi Power's effective tax rate (benefit rate) was 19.0%(205.6)% for the six months ended June 30, 20152016 compared to (51.1)%19.0% for the corresponding period in 2014.2015. The increaseeffective tax rate decrease was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equityincreased tax benefits related to the estimated probable losses on construction of the Kemper IGCC.
Southern Power
Southern Power's effective tax rate (benefit rate) was 13.7%(74.0)% for the six months ended June 30, 20152016 compared to 0.3%13.7% for the corresponding period in 2014.2015. The increaseeffective tax rate decrease was primarily due to beneficial changes that impacted 2014 state income taxes, which were partially offset by increased federal income tax benefits from ITCs related to ITCssolar projects expected to be placed in the current year.service in 2016 and additional PTCs related to wind projects in 2016 compared to 2015.
Unrecognized Tax Benefits
See Note 5 to the financial statements of Southern Companyeach registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.
Changes during 2015 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2014 | $ | 165 |
| | $ | 5 |
| | $ | 170 |
|
| Tax positions from current periods | — |
| | 2 |
| | 2 |
|
| Tax positions from prior periods | 230 |
| | — |
| | 231 |
|
| Reductions due to settlements | (5 | ) | | — |
| | (5 | ) |
| Balance as of June 30, 2015 | $ | 390 |
| | $ | 7 |
| | $ | 398 |
|
The tax positions from prior periods relate primarily to 2008 through 2013 amended federal income tax returns that were filed to include deductions for Kemper IGCC-related R&E expenditures. See "Section 174 Research and Experimental Deduction" herein for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Changes during 2016 for unrecognized tax benefits were as follows:
|
| | | | | | | | | | | |
| | Mississippi Power | | Southern Power | | Southern Company |
| | (in millions) |
| Unrecognized tax benefits as of December 31, 2015 | $ | 421 |
| | $ | 8 |
| | $ | 433 |
|
| Tax positions from current periods | — |
| | 9 |
| | 10 |
|
| Balance as of June 30, 2016 | $ | 421 |
| | $ | 17 |
| | $ | 443 |
|
The tax positions from current periods primarily relate to federal income tax benefits from ITCs impacting the estimated annual effective tax rate for interim reporting purposes.
The impact on the effective tax rate, if recognized, wasis as follows:
| | | | As of June 30, 2015 | | As of December 31, 2014 | As of June 30, 2016 | | As of December 31, 2015 |
| | 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 | $ | — |
| | $ | 7 |
| | $ | 8 |
| | $ | 10 |
| $ | (2 | ) | | $ | 17 |
| | $ | 20 |
| | $ | 10 |
|
| Tax positions not impacting the effective tax rate | 390 |
| | — |
| | 390 |
| | 160 |
| 423 |
| | — |
| | 423 |
| | 423 |
|
| Balance of unrecognized tax benefits | $ | 390 |
| | $ | 7 |
| | $ | 398 |
| | $ | 170 |
| $ | 421 |
| | $ | 17 |
| | $ | 443 |
| | $ | 433 |
|
The tax positions impacting the effective tax rate primarily relate to federal income tax benefits related tofrom ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related R&Eresearch and experimental (R&E) expenditures. See "Section"Section 174 Research and Experimental Deduction" hereinDeduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.
Accrued interest for all tax positions other than 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 could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. 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.
Section 174 Research and Experimental Deduction
Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax returnhas reflected deductions for R&E expenditures related to the Kemper IGCC. In May 2015, Southern CompanyIGCC in its federal income tax calculations since 2013 and has filed amended its 2008 through 2013 federal income tax returns for 2008 through 2013 to also include deductions for Kemper IGCC-related R&E expenditures.such deductions.
The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power and Southern Company had related unrecognized tax benefits associated with these R&E deductions of approximately $390$423 million and associated interest of $5$15 million as of June 30, 2015.
2016. The ultimate outcome of this matter cannot be determined at this time.
Southern Company, the traditional electric operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, 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. 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 gross basis. See Note (C) herein 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
The traditional electric operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional electric operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.
To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.
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' 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(which are mainly used to hedge anticipated purchases and sales andsales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.
Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At June 30, 2015,2016, 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 | | 220 | | 2020 | | 2017 | | 250 | | 2020 | | 2016 |
| Alabama Power | | 49 | | 2018 | | — | | 60 | | 2019 | | — |
| Georgia Power | | 47 | | 2017 | | — | | 82 | | 2019 | | — |
| Gulf Power | | 80 | | 2020 | | — | | 66 | | 2020 | | — |
| Mississippi Power | | 43 | | 2018 | | — | | 29 | | 2019 | | — |
| Southern Power | | 1 | | 2015 | | 2017 | | 13 | | 2017 | | 2016 |
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 53 million mmBtu for Southern Company 1 million mmBtu for Alabama Power, 3 million mmBtu forand Georgia Power, and 1 million mmBtu for Southern Power.
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 20162017 are immaterial for all registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
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 June 30, 2015,2016, 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 June 30, 2015 | | Notional Amount | | Interest Rate Received | | Weighted Average Interest Rate Paid | | Hedge Maturity Date | | Fair Value
Gain (Loss) at June 30, 2016 |
| | | (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 | | |
| Alabama Power | | $ | 200 |
| | 3-month
LIBOR | | 2.93% | | October 2025 | | $ | (7 | ) | |
| Gulf Power | | | $ | 80 |
| | 3-month
LIBOR | | 2.32% | | December 2026 | | $ | (7 | ) |
| Cash Flow Hedges of Existing Debt | | Cash Flow Hedges of Existing Debt | | |
| Southern Company | | | 8 |
| (d) | 3-month
LIBOR | | 1.73% | | June 2020 | | — |
|
| Southern Company | | | 3 |
| (d) | 3-month
LIBOR | | 1.73% | | June 2020 | | — |
|
| Georgia Power | | 350 |
| | 3-month
LIBOR | | 2.57% | | November 2025 | | (1 | ) | | 200 |
| | 3-month
LIBOR + 0.40% | | 1.01% | | August 2016 | | — |
|
| Cash Flow Hedges of Existing Debt | | | |
| Georgia Power | | 250 |
| | 3-month
LIBOR + 0.32% | | 0.75% | | March 2016 | | — |
| |
| Georgia Power | | 200 |
| | 3-month
LIBOR + 0.40% | | 1.01% | | August 2016 | | — |
| |
| Fair Value Hedges on Existing Debt | | | |
| Fair Value Hedges of Existing Debt | | Fair Value Hedges of Existing Debt | | |
| Southern Company | | 250 |
| | 1.30% | | 3-month
LIBOR + 0.17% | | August 2017 | | 2 |
| | 250 |
| | 1.30% | | 3-month
LIBOR + 0.17% | | August 2017 | | 2 |
|
| Southern Company | | 300 |
| | 2.75% | | 3-month LIBOR + 0.92% | | June 2020 | | 1 |
| | 300 |
| | 2.75% | | 3-month
LIBOR + 0.92% | | June 2020 | | 11 |
|
| Georgia Power | | 250 |
| | 5.40% | | 3-month
LIBOR + 4.02% | | June 2018 | | 1 |
| | 250 |
| | 5.40% | | 3-month
LIBOR + 4.02% | | June 2018 | | 3 |
|
| Georgia Power | | 200 |
| | 4.25% | | 3-month
LIBOR + 2.46% | | December 2019 | | 1 |
| | 200 |
| | 4.25% | | 3-month
LIBOR + 2.46% | | December 2019 | | 6 |
|
| Georgia Power | | | 500 |
| | 1.95% | | 3-month
LIBOR + 0.76% | | December 2018 | | 5 |
|
| Derivatives not Designated as Hedges | | Derivatives not Designated as Hedges | | |
| Southern Power | | | 65 |
| (a,d) | 3-month
LIBOR | | 2.50% | | October 2016 | (e) | — |
|
| Southern Power | | | 47 |
| (b,d) | 3-month
LIBOR | | 2.21% | | October 2016 | (e) | — |
|
| Southern Power | | | 65 |
| (c,d) | 3-month
LIBOR | | 2.21% | | November 2016 | (f) | — |
|
| Total | | $ | 2,000 |
| | $ | (3 | ) | | $ | 1,968 |
| | $ | 20 |
|
| |
| (a) | 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. |
| |
| (b) | 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. |
| |
| (c) | 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. |
| |
| (d) | Amortizing notional amount. |
| |
| (e) | Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap. |
| |
| (f) | Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
The estimated pre-tax gains (losses) that willexpected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 20162017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.2046.
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 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 June 30, 2016, the following foreign currency derivatives were outstanding: |
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge
Maturity Date | Fair Value
Gain (Loss) at June 30, 2016 |
| (in millions) | | (in millions) | | | (in millions) |
| Cash Flow Hedges of Existing Debt | | | | | |
| Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (17 | ) |
| Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (21 | ) |
| Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (38 | ) |
The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2017 are $(24) million for Southern Company and Southern Power.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Derivative Financial Statement Presentation and Amounts
At June 30, 2015,2016, the fair value of energy-related derivatives, and interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
| | | Asset Derivatives at June 30, 2015 | |
| Asset Derivatives at June 30, 2016 | | Asset Derivatives at June 30, 2016 |
| | | Fair Value | | Fair Value |
| Derivative Category and Balance Sheet Location | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | | (in millions) | | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Other current assets | | $ | 5 |
| | $ | 2 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | N/A |
| | $ | 12 |
| | $ | 5 |
| | $ | 6 |
| | $ | 1 |
| | $ | — |
| | |
| Other deferred charges and assets | | | 16 |
| | 5 |
| | 9 |
| | 1 |
| | 1 |
| | |
| Total derivatives designated as hedging instruments for regulatory purposes | | | $ | 28 |
| | $ | 10 |
| | $ | 15 |
| | $ | 2 |
| | $ | 1 |
| | N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | |
| Other current assets | | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Other deferred charges and assets | | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Interest rate derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Other current assets | | $ | 11 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 11 |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
| Other deferred charges and assets | | | 16 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | | $ | 33 |
| | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
| Derivatives not designated as hedging instruments | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | |
| Other current assets | | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| Total asset derivatives | | $ | 16 |
| | $ | 2 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 63 |
| | $ | 10 |
| | $ | 29 |
| | $ | 2 |
| | $ | 1 |
| | $ | 8 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Liability Derivatives at June 30, 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: | | | | | | | | | | | | |
Other current liabilities(*) | | $ | 99 |
| | $ | 31 |
| | $ | 15 |
| | $ | 32 |
| | $ | 21 |
| | |
| Other deferred credits and liabilities | | 81 |
| | 17 |
| | 2 |
| | 42 |
| | 20 |
| | |
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 180 |
| | $ | 48 |
| | $ | 17 |
| | $ | 74 |
| | $ | 41 |
| | N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | | | | |
| Interest rate derivatives: | | | | | | | | | | | | |
Other current liabilities(*) | | $ | 8 |
| �� | $ | 7 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Other deferred credits and liabilities | | 6 |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
| Total derivatives designed as hedging instruments in cash flow and fair value hedges | | $ | 14 |
| | $ | 7 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total liability derivatives | | $ | 194 |
| | $ | 55 |
| | $ | 21 |
| | $ | 74 |
| | $ | 41 |
| | $ | — |
|
(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Liability Derivatives at June 30, 2016 |
| | | 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(*) | | $ | 61 |
| | $ | 17 |
| | $ | 4 |
| | $ | 25 |
| | $ | 15 |
| | |
| Other deferred credits and liabilities | | 44 |
| | 5 |
| | 1 |
| | 30 |
| | 8 |
| | |
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 105 |
| | $ | 22 |
| | $ | 5 |
| | $ | 55 |
| | $ | 23 |
| | N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | |
Liabilities from risk management activities(*) | | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Other deferred credits and liabilities | | 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
| Interest rate derivatives: | | | | | | | | | | | | |
Liabilities from risk management activities(*) | | 7 |
| | — |
| | — |
| | 7 |
| | — |
| | — |
|
| Foreign currency derivatives: | | | | | | | | | | | | |
Liabilities from risk management activities(*) | | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
|
| Other deferred credits and liabilities | | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | 49 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 42 |
|
| Derivatives not designated as hedging instruments | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Energy-related derivatives: | | | | | | | | | | | | |
| Other current liabilities | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Total liability derivatives | | $ | 155 |
| | $ | 22 |
| | $ | 5 |
| | $ | 62 |
| | $ | 23 |
| | $ | 43 |
|
| |
| (*) | Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities." |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At December 31, 2014,2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:
| | | Asset Derivatives at December 31, 2014 | |
| Asset Derivatives at December 31, 2015 | | Asset Derivatives at December 31, 2015 |
| | | Fair Value | | Fair Value |
| Derivative Category and Balance Sheet Location | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | | (in millions) | | (in millions) |
| Derivatives designated as hedging instruments for regulatory purposes | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Other current assets | | $ | 7 |
| | $ | 1 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | | | $ | 3 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | N/A |
|
| Other deferred charges and assets | | — |
| | — |
| | 1 |
| | — |
| | — |
| | | |
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 7 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | N/A |
| |
| 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 | | $ | 7 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 19 |
| | — |
| | 5 |
| | 1 |
| | — |
| | — |
|
| Other deferred charges and assets | | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| |
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | 8 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
| Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
| Other current assets | | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
| Other current assets | | | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
| Total derivatives not designated as hedging instruments | | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Total asset derivatives | | $ | 21 |
| | $ | 1 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 29 |
| | $ | 1 |
| | $ | 7 |
| | $ | 1 |
| | $ | — |
| | $ | 7 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Liability Derivatives at December 31, 2014 |
| | | 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: | | | | | | | | | | | | |
Other current liabilities(*) | | $ | 118 |
| | $ | 32 |
| | $ | 23 |
| | $ | 37 |
| | $ | 26 |
| |
|
|
| Other deferred credits and liabilities | | 79 |
| | 21 |
| | 4 |
| | 35 |
| | 19 |
| |
|
|
| Total derivatives designated as hedging instruments for regulatory purposes | | $ | 197 |
| | $ | 53 |
| | $ | 27 |
| | $ | 72 |
| | $ | 45 |
| | N/A |
|
| Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | | | | | | | | | |
| Interest rate derivatives: | | | | | | | | | | | | |
Other current liabilities(*) | | $ | 17 |
| | $ | 8 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Other deferred credits and liabilities | | 7 |
| | — |
| | 5 |
| | — |
| | — |
| | — |
|
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | | $ | 24 |
| | $ | 8 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Derivatives not designated as hedging instruments | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | |
| Other current liabilities | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| Total liability derivatives | | $ | 225 |
| | $ | 61 |
| | $ | 41 |
| | $ | 72 |
| | $ | 45 |
| | $ | 4 |
|
(*) Gulf Power includes current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities." |
| | | | | | | | | | | | | | | | | | | | | | | | |
| 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 |
|
| |
| (*) | Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities." |
The derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and 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, and foreign currency derivative contracts at June 30, 20152016 and December 31, 20142015 are presented in the following tables.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Derivative Contracts at June 30, 2015 | |
| Derivative Contracts at June 30, 2016 | | Derivative Contracts at June 30, 2016 |
| | | Fair Value | Fair Value |
| | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | | (in millions) | (in millions) |
| Assets | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 5 |
| | $ | 2 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 36 |
| | $ | 10 |
| | $ | 15 |
| | $ | 2 |
| | $ | 1 |
| | $ | 8 |
|
Gross amounts not offset in the Balance Sheet (b) | | (5 | ) | | (2 | ) | | (3 | ) | | — |
| | — |
| | — |
| (32 | ) | | (8 | ) | | (4 | ) | | (2 | ) | | (1 | ) | | (3 | ) |
| Net energy-related derivative assets | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 4 |
| | $ | 2 |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 11 |
| | $ | — |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Interest rate and foreign currency derivatives: | | | | | | | | | | | | |
Interest rate and foreign currency derivatives presented in the Balance Sheet (a) | | $ | 27 |
| | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (3 | ) | | — |
| | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Net interest rate derivative assets | | $ | 3 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Net interest rate and foreign currency derivative assets | | $ | 9 |
| | $ | — |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 180 |
| | $ | 48 |
| | $ | 17 |
| | $ | 74 |
| | $ | 41 |
| | $ | — |
| $ | 110 |
| | $ | 22 |
| | $ | 5 |
| | $ | 55 |
| | $ | 23 |
| | $ | 5 |
|
Gross amounts not offset in the Balance Sheet (b) | | (5 | ) | | (2 | ) | | (3 | ) | | — |
| | — |
| | — |
| (32 | ) | | (8 | ) | | (4 | ) | | (2 | ) | | (1 | ) | | (3 | ) |
| Net energy-related derivative liabilities | | $ | 175 |
| | $ | 46 |
| | $ | 14 |
| | $ | 74 |
| | $ | 41 |
| | $ | — |
| $ | 78 |
| | $ | 14 |
| | $ | 1 |
| | $ | 53 |
| | $ | 22 |
| | $ | 2 |
|
| Interest rate derivatives: | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 14 |
| | $ | 7 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Interest rate and foreign currency derivatives: | | | | | | | | | | | | |
Interest rate and foreign currency derivatives presented in the Balance Sheet (a) | | $ | 45 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 38 |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (3 | ) | | — |
| | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
| Net interest rate derivative liabilities | | $ | 6 |
| | $ | 7 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
| Net interest rate and foreign currency derivative liabilities | | $ | 27 |
| | $ | — |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 38 |
|
| |
| (a) | None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
| (b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
| | | Derivative Contracts at December 31, 2014 | |
| Derivative Contracts at December 31, 2015 | | Derivative Contracts at December 31, 2015 |
| | | Fair Value | | Fair Value |
| | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Power |
| | | (in millions) | | (in millions) |
| Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 13 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 7 |
| | $ | 1 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (7 | ) | | — |
| | — |
| | — |
| | (6 | ) | | (1 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) |
| Net energy-related derivative assets | | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Interest rate derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 8 |
| | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | 5 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (9 | ) | | — |
| | (4 | ) | | — |
| | — |
| | — |
|
| Net interest rate derivative assets | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 13 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
Energy-related derivatives presented in the Balance Sheet (a) | | $ | 201 |
| | $ | 53 |
| | $ | 27 |
| | $ | 72 |
| | $ | 45 |
| | $ | 4 |
| | $ | 220 |
| | $ | 55 |
| | $ | 15 |
| | $ | 100 |
| | $ | 47 |
| | $ | 3 |
|
Gross amounts not offset in the Balance Sheet (b) | | (9 | ) | | — |
| | (7 | ) | | — |
| | — |
| | — |
| | (6 | ) | | (1 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) |
| Net energy-related derivative liabilities | | $ | 192 |
| | $ | 53 |
| | $ | 20 |
| | $ | 72 |
| | $ | 45 |
| | $ | 4 |
| | $ | 214 |
| | $ | 54 |
| | $ | 13 |
| | $ | 100 |
| | $ | 47 |
| | $ | 2 |
|
| Interest rate derivatives: | | | | | | | | | | | | | | | | | | | | | | | | |
Interest rate derivatives presented in the Balance Sheet (a) | | $ | 24 |
| | $ | 8 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 30 |
| | $ | 15 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Gross amounts not offset in the Balance Sheet (b) | | (8 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (9 | ) | | — |
| | (4 | ) | | — |
| | — |
| | — |
|
| Net interest rate derivative liabilities | | $ | 16 |
| | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21 |
| | $ | 15 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| |
| (a) | None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. |
| |
| (b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.
(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
At June 30, 20152016 and December 31, 2014,2015, 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 on the Balance Sheet at June 30, 2015 | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2016 | | Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 2016 |
Derivative Category and Balance Sheet Location | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | | (in millions) | | (in millions) |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | |
| Other regulatory assets, current | | $ | (99 | ) | | $ | (31 | ) | | $ | (15 | ) | | $ | (32 | ) | | $ | (21 | ) | | $ | (61 | ) | | $ | (17 | ) | | $ | (4 | ) | | $ | (25 | ) | | $ | (15 | ) |
| Other regulatory assets, deferred | | (81 | ) | | (17 | ) | | (2 | ) | | (42 | ) | | (20 | ) | | (44 | ) | | (5 | ) | | (1 | ) | | (30 | ) | | (8 | ) |
Other regulatory liabilities, current (a) | | 5 |
| | 2 |
| | 3 |
| | — |
| | — |
| | 12 |
| | 5 |
| | 6 |
| | 1 |
| | — |
|
Other regulatory liabilities, deferred (b) | | — |
| | — |
| | — |
| | — |
| | — |
| | 16 |
| | 5 |
| | 9 |
| | 1 |
| | 1 |
|
| Total energy-related derivative gains (losses) | | $ | (175 | ) | | $ | (46 | ) | | $ | (14 | ) | | $ | (74 | ) | | $ | (41 | ) | | $ | (77 | ) | | $ | (12 | ) | | $ | 10 |
| | $ | (53 | ) | | $ | (22 | ) |
(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.
(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
| |
| (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 on the Balance Sheet at December 31, 2014 | |
| Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015 | | Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015 |
Derivative Category and Balance Sheet Location | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power | | Southern Company | | Alabama Power | | Georgia Power | | Gulf Power | | Mississippi Power |
| | | (in millions) | | (in millions) |
| Energy-related derivatives: | | | | | | | | | | | | | | | | | | | | |
| Other regulatory assets, current | | $ | (118 | ) | | $ | (32 | ) | | $ | (23 | ) | | $ | (37 | ) | | $ | (26 | ) | | $ | (130 | ) | | $ | (40 | ) | | $ | (12 | ) | | $ | (49 | ) | | $ | (29 | ) |
| Other regulatory assets, deferred | | (79 | ) | | (21 | ) | | (4 | ) | | (35 | ) | | (19 | ) | | (87 | ) | | (15 | ) | | (3 | ) | | (51 | ) | | (18 | ) |
Other regulatory liabilities, current (a) | | 7 |
| | 1 |
| | 6 |
| | — |
| | — |
| |
Other regulatory liabilities, deferred (b) | | — |
| | — |
| | 1 |
| | — |
| | — |
| |
Other regulatory liabilities, current(*) | | | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
|
| Total energy-related derivative gains (losses) | | $ | (190 | ) | | $ | (52 | ) | | $ | (20 | ) | | $ | (72 | ) | | $ | (45 | ) | | $ | (214 | ) | | $ | (54 | ) | | $ | (13 | ) | | $ | (100 | ) | | $ | (47 | ) |
| |
| (*) | Georgia Power includes other regulatory liabilities, current in other current liabilities. |
(a) Southern Company, Alabama Power, and Georgia Power include other regulatory liabilities, current in other current liabilities.
(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.
For the three months ended June 30, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows:
|
| | | | | | | | | | | | | | | | | | |
Derivatives in Cash Flow Hedging Relationships | | Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | | Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
| | | Statements of Income Location | | Amount |
| | | 2015 | | 2014 | | | | 2015 | | 2014 |
| | | (in millions) | | | | (in millions) |
| Southern Company | | | | | | | | | | |
| Interest rate derivatives | | $ | 31 |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (2 | ) | | $ | (2 | ) |
| Alabama Power | | | | | | | | | | |
| Interest rate derivatives | | $ | 7 |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | — |
|
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives | | $ | 24 |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | — |
|
| Mississippi Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | — |
| | $ | (1 | ) |
| Southern Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | — |
| | $ | (1 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three months ended June 30, 2016 and 2015, the pre-tax effects of 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 |
| | | 2016 | | 2015 | | | | 2016 | | 2015 |
| | | (in millions) | | | | (in millions) |
| Southern Company | | | | | | | | | | |
| Interest rate derivatives | | $ | 6 |
| | $ | 31 |
| | Interest expense, net of amounts capitalized | | $ | (4 | ) | | $ | (2 | ) |
| Foreign currency derivatives | | (39 | ) | | — |
| | Interest expense, net of amounts capitalized | | (1 | ) |
| — |
|
| | | | | | | Other income (expense), net | | (20 | ) |
| — |
|
| Total | | $ | (33 | ) | | $ | 31 |
| | | | $ | (25 | ) | | $ | (2 | ) |
| Alabama Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 7 |
| | Interest expense, net of amounts capitalized | | $ | (2 | ) | | $ | (1 | ) |
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 24 |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | (1 | ) |
| Gulf Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (2 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | | $ | — |
| | $ | — |
|
| Southern Power | | | | | | | | | | |
| Foreign currency derivatives | | $ | (39 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | — |
|
| | | | | | | Other income (expense), net | | (20 | ) | | — |
|
| Total | | $ | (39 | ) | | $ | — |
| | | | $ | (21 | ) | | $ | — |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the six months ended June 30, 20152016 and 2014,2015, the pre-tax effects of interest rate derivatives and foreign currency derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.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 |
| | | 2016 | | 2015 | | | | 2016 | | 2015 |
| | | (in millions) | | | | (in millions) |
| Southern Company | | | | | | | | | | |
| Interest rate derivatives | | $ | (184 | ) | | $ | 2 |
| | Interest expense, net of amounts capitalized | | $ | (7 | ) | | $ | (4 | ) |
| Foreign currency derivatives | | (39 | ) | | — |
| | Interest expense, net of amounts capitalized | | (1 | ) | | — |
|
| | | | | | | Other income (expense), net | | (20 | ) | | — |
|
| Total | | $ | (223 | ) | | $ | 2 |
| | | | $ | (28 | ) | | $ | (4 | ) |
| Alabama Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (4 | ) | | $ | 1 |
| | Interest expense, net of amounts capitalized | | $ | (3 | ) | | $ | (1 | ) |
| Georgia Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | 1 |
| | Interest expense, net of amounts capitalized | | $ | (2 | ) | | $ | (2 | ) |
| Gulf Power | | | | | | | | | | |
| Interest rate derivatives | | $ | (7 | ) | | $ | — |
| | Interest expense, net of amounts capitalized | | $ | — |
| | $ | — |
|
| Mississippi Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | (1 | ) |
| Southern Power | | | | | | | | | | |
| Interest rate derivatives | | $ | — |
| | $ | — |
| | Interest expense, net of amounts capitalized | | $ | (1 | ) | | $ | — |
|
| Foreign currency derivatives | | (39 | ) | | — |
| | Interest expense, net of amounts capitalized | | (1 | ) | | — |
|
| | | | | | | Other income (expense), net | | (20 | ) | | — |
|
| Total | | $ | (39 | ) | | $ | — |
| | | | $ | (22 | ) | | $ | — |
|
For the three and six months ended June 30, 20152016 and 2014,2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.
For the three and six months ended June 30, 20152016 and 2014,2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore,
For the six months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:
|
| | | | | | | | |
| Derivatives in Fair Value Hedging Relationships | | | | |
| | | Gain (Loss) |
| Derivative Category | Statements of Income Location | 2016 | | 2015 |
| | | (in millions) |
| Southern Company | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | 24 |
| | $ | 4 |
|
| Georgia Power | | | | |
| Interest rate derivatives: | Interest expense, net of amounts capitalized | $ | 15 |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
For the three and six months ended June 30, 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 six months ended June 30, 20152016 and 2014,2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.
Contingent Features
The registrants 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 June 30, 2015,2016, the registrants' collateral posted with their derivative counterparties was immaterial.
At June 30, 2015,2016, the fair value of derivative liabilities with contingent features was $49$24 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 $49$24 million and 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.
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, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, and Southern Power 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, and Southern Power 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', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional electric operating companies, and Southern Power 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, formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the financial statementsdistribution 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 Power under "2014 – SG2 Imperial Valley, LLC" in Item 8 of the Form 10-K for additional information. During the second quarter 2015, the fair values of the assets acquired of SG2 Imperial Valley, LLC were finalized and recorded as follows: $707 million as property, plant, and equipment and $20 million as prepayments related to transmission services.Company.
During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy. Acquisition-related costs were expensed as incurred and were not material.
Kay County Wind Facility
On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Clean Energy Holdings, LLC,The Merger will be accounted for using the developeracquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the project,acquisition date. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities will be recorded as goodwill. The following table presents the preliminary purchase price allocation:
|
| | | |
| Southern Company Gas Purchase Price | June 30, 2016 |
| | (in millions) |
| Current assets | $ | 1,474 |
|
| Property, plant, and equipment | 9,795 |
|
| Goodwill | 6,333 |
|
| Intangible assets | 436 |
|
| Regulatory assets | 846 |
|
| Other assets | 273 |
|
| Current liabilities | (2,205 | ) |
| Other liabilities | (4,529 | ) |
| Long-term debt | (4,261 | ) |
| Noncontrolling interests | (160 | ) |
| Total purchase price | $ | 8,002 |
|
The estimated fair values noted above are preliminary and are subject to acquirechange 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 may have a material impact on the results of operations and financial position of Southern Company.
During the three and six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.
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 membership interestsstock of Kay Wind, LLC (Kay Wind)PowerSecure, a leading provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for approximately $492 million, with potential$18.75 per common share in cash, resulting in an aggregate purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, as well as various other customary conditions to closing, and is expected to close in the fourth quarter 2015. The ultimate outcome of this matter cannot be determined at this time.
Lost Hills-Blackwell Solar Facilities
On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from$429 million. As a result, PowerSecure became a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $33 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 22-MW Lost Hills and the approximately 13-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville, California and then to Pacific Gas and Electric Company, that together extend approximately 29 years. As of June 30, 2015, the fair values of the assets acquired were recorded as follows: $98 million as property, plant, and equipment and $9 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration.Company.
North Star Solar Facility
On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $211 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $100 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star constructed and owns the approximately 61-MW North Star solar facility in Fresno County, California. The solar facility began commercial operation on June 20, 2015, and the entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. As of June 30, 2015, the fair values of the assets acquired were recorded as follows: $266 million as property, plant, and equipment, $24 million as an intangible asset, and $21 million as a receivable related to transmission interconnection costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration.
Construction Projects
In December 2014, Southern Power Company announced plans to build a solar photovoltaic facility, and during 2015, Southern Power Company acquired all the outstanding membership interests of five separate solar project development entities. The construction projects are in accordance with Southern Power's overall growth strategy and included in its capital program estimates for 2015. The total cost of construction incurred for these projects through June 30, 2015 was $188 million. The ultimate outcome of these matters cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Southern Power Company's construction projects are detailed inThe aggregate purchase price was allocated on a preliminary basis to the table below:assets acquired and liabilities assumed based upon the current determination of fair values at the date of acquisition. The preliminary allocation of the purchase price is as follows:
|
| | | | | | | | | | | | |
| Solar Project | Seller | Nameplate Capacity | County Location in Georgia | Expected Commercial Operation Date | PPA Counterparty for Entire Plant Output | PPA Contract Period | Estimated Construction Cost | |
| | | (MW) | | | | | (in millions) | |
| Taylor County | N/A | 146 | Taylor | Fourth quarter 2016 | Cobb, Flint, and Sawnee Electric Membership Corporations | 25 years | $ | 260 |
| - | $280 | |
| Decatur Parkway | TradeWind Energy, Inc. | 84 | Decatur | December 2015 | Georgia Power(a) | 25 years | $ | 170 |
| - | $173 | (b) |
| Decatur County | TradeWind Energy, Inc. | 20 | Decatur | December 2015 | Georgia Power(a) | 20 years | $ | 45 |
| - | $47 | (b) |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor | December 2016 | Georgia Power(a) | 30 years | $ | 220 |
| - | $230 | (b) |
| Pawpaw | Longview Solar, LLC | 30 | Taylor | December 2015 | Georgia Power(a) | 30 years | $ | 70 |
| - | $80 | (b) |
| Butler Solar Farm | Strata Solar Development, LLC | 20 | Taylor | December 2015 | Georgia Power(a) | 20 years | $ | 42 |
| - | $48 | (b) |
|
| | | |
| PowerSecure Purchase Price | June 30, 2016 |
| | (in millions) |
| Current assets | $ | 174 |
|
| Property, plant, and equipment | 48 |
|
| Goodwill | 262 |
|
| Intangible assets | 99 |
|
| Other assets | 8 |
|
| Current liabilities | (111 | ) |
| Long-term debt, including current portion | (47 | ) |
| Deferred credits and other liabilities | (4 | ) |
| Total purchase price | $ | 429 |
|
(a) SubjectThe excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $262 million was recognized as goodwill, which is primarily attributable to FERC approval.the 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. Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.
(b) IncludesThe preliminary valuation of identifiable intangible assets included customer relationships, trade names, patents, and backlog with estimated lives of three 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.
Natural Gas Pipeline Venture
On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Southern Company expects to finance the purchase price of all outstanding membership interests.approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.
The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.
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. During the six months ended June 30, 2016, the fair values of the assets and liabilities acquired of Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, and Roserock were finalized and there were no changes.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects discussed below. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.
|
| | | | | | | | | | |
| Project Facility | Resource | Seller; Acquisition Date | Approx. Nameplate Capacity | Location | Southern Power Percentage Ownership | | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period |
| | | | (MW) | | | | | | |
| Acquisitions for the Six Months Ended June 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 | % | | Fourth quarter 2016 | Austin Energy | 15 years |
| 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 |
| Passadumkeag | Wind | Quantum Utility Generation, LLC June 30, 2016 | 42 | Penobscot County, ME | 100 | % | | July 2016 | Western Massachusetts Electric Company | 15 years |
| Acquisitions Subsequent to June 30, 2016 |
| Henrietta | Solar | SunPower Corp. July 1, 2016 | 102 | Kings County, CA | 51 | % | (*) | July 2016 | Pacific Gas and Electric Company | 20 years |
| Lamesa | Solar | RES America Developments Inc. July 1, 2016 | 102 | Dawson County, TX | 100 | % | | Second quarter 2017 | City of Garland, Texas | 15 years |
| Rutherford | Solar | Cypress Creek Renewables, LLC July 1, 2016 | 74 | Rutherford County, NC | 90 | % | | Fourth quarter 2016 | Duke Energy Carolinas, LLC | 15 years |
| |
| (*) | 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. |
Acquisitions During the Six Months Ended June 30, 2016
Southern Power's aggregate purchase price for the project facilities acquired during the six months ended June 30, 2016 is approximately $477 million, which includes $6 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria, the total aggregate purchase price is approximately $483 million for the project facilities acquired during the six months ended June 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $426 million as CWIP, $58 million as property, plant, and equipment, $4 million as other assets, and $7 million as accounts payable; however, the allocations of the purchase price to individual assets have not been finalized. For East Pecos, which is currently under construction, total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million. The ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Acquisitions Subsequent to June 30, 2016
Southern Power's aggregate purchase price for acquisitions subsequent to June 30, 2016 is approximately $275 million. Including the minority owner, SunPower Corp.'s 49% ownership interest in Henrietta, and TRE's 10% ownership interest in Rutherford, the aggregate total purchase price is approximately $447 million for the project facilities acquired subsequent to June 30, 2016. The aggregate purchase price includes the assumption of $217 million in construction debt (non-recourse to Southern Power). For Lamesa and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million. The ultimate outcome of these matters cannot be determined at this time.
Acquisition Agreements Executed but Not Yet Closed
During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. 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 six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 million. The aggregate amount of net income, excluding impacts of ITCs and PTCs, attributable to Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their 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 2015 period is not meaningful and has been omitted.
Construction Projects
During the six months ended June 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
|
| | | | | | |
| Solar Facility | Seller | Approx. Nameplate Capacity | Location | Expected/Actual COD | PPA Counterparties for Plant Output | PPA Contract Period |
| | (MW) | | | | |
| Butler | CERSM, LLC and Community Energy, Inc. | 103 | Taylor County, GA | Fourth quarter 2016 | Georgia Power(a) | 30 years |
Desert Stateline(b) | First Solar Development, LLC | 299(c) | San Bernardino County, CA | Through third quarter 2016 | Southern California Edison Company (SCE) | 20 years |
| Garland and Garland A | Recurrent Energy, LLC | 205 | Kern County, CA | Fourth quarter 2016 and
Third quarter 2016 | SCE | 15 years and
20 years |
| Roserock | Recurrent Energy, LLC | 160 | Pecos County, TX | Fourth quarter 2016 | Austin Energy | 20 years |
| Sandhills | N/A | 146 | Taylor County, GA | Fourth quarter 2016 | Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations | 25 years |
| Tranquillity | Recurrent Energy, LLC | 205 | Fresno County, CA | July 2016 | Shell Energy North America (US), LP/SCE | 18 years |
| |
| (a) | Butler - Affiliate PPA approved by the FERC. |
| |
| (b) | Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. |
(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
(J) SEGMENT AND RELATED INFORMATION
The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power. 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 generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.
Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies and Southern Power. Revenues from sales by Southern Power to the traditional electric operating companies were $107 million and $204 million for the three and six months ended June 30, 2016, respectively, and $85 million and $199 million for the three and six months ended June 30, 2015, respectively, and $68 million and $140 million for the three and six months ended June 30, 2014, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
Financial data for business segments and products and services for the three and six months ended June 30, 20152016 and 20142015 was as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | | | |
| | Traditional Operating Companies | | Southern Power | | Eliminations | | Total | | All Other | | Eliminations | | Consolidated |
| | (in millions) |
| Three Months Ended June 30, 2015: | | | | | | | | | | | | | |
| Operating revenues | $ | 4,077 |
| | $ | 337 |
| | $ | (90 | ) | | $ | 4,324 |
| | $ | 43 |
| | $ | (30 | ) | | $ | 4,337 |
|
Segment net income (loss)(a)(b) | 561 |
| | 46 |
| | — |
| | 607 |
| | 18 |
| | 4 |
| | 629 |
|
| Six Months Ended June 30, 2015: | | | | | | | | | | | | | |
| Operating revenues | $ | 8,025 |
| | $ | 684 |
| | $ | (213 | ) | | $ | 8,496 |
| | $ | 83 |
| | $ | (59 | ) | | $ | 8,520 |
|
Segment net income (loss)(a)(c) | 1,038 |
| | 79 |
| | — |
| | 1,117 |
| | 21 |
| | — |
| | 1,138 |
|
| Total assets at June 30, 2015 | $ | 67,362 |
| | $ | 6,226 |
| | $ | (277 | ) | | $ | 73,311 |
| | $ | 1,360 |
| | $ | (490 | ) | | $ | 74,181 |
|
| Three Months Ended June 30, 2014: | | | | | | | | | | | | | |
| Operating revenues | $ | 4,209 |
| | $ | 329 |
| | $ | (84 | ) | | $ | 4,454 |
| | $ | 39 |
| | $ | (26 | ) | | $ | 4,467 |
|
Segment net income (loss)(a) | 580 |
| | 31 |
| | — |
| | 611 |
| | 2 |
| | (2 | ) | | 611 |
|
| Six Months Ended June 30, 2014: | | | | | | | | | | | | | |
| Operating revenues | $ | 8,587 |
| | $ | 680 |
| | $ | (186 | ) | | $ | 9,081 |
| | $ | 80 |
| | $ | (50 | ) | | $ | 9,111 |
|
Segment net income (loss)(a)(c) | 899 |
| | 64 |
| | — |
| | 963 |
| | 2 |
| | (3 | ) | | 962 |
|
| Total assets at December 31, 2014 | $ | 64,644 |
| | $ | 5,550 |
| | $ | (131 | ) | | $ | 70,063 |
| | $ | 1,156 |
| | $ | (296 | ) | | $ | 70,923 |
|
(a) After dividends on preferred and preference stock of subsidiaries.(b) Segment net income (loss) for the traditional operating companies for the three months ended June 30, 2015 includes a $23 million pre-tax charge ($14 million after tax) for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Electric Utilities | | | | | | |
| | Traditional Electric Operating Companies | | Southern Power | | Eliminations | | Total | | All Other | | Eliminations | | Consolidated |
| | (in millions) |
| Three Months Ended June 30, 2016: | | | | | | | | | | | | | |
| Operating revenues | $ | 4,115 |
| | $ | 373 |
| | $ | (109 | ) | | $ | 4,379 |
| | $ | 125 |
| | $ | (45 | ) | | $ | 4,459 |
|
Segment net income (loss)(a)(b) | 595 |
| | 89 |
| | — |
| | 684 |
| | (68 | ) | | (4 | ) | | 612 |
|
| Six Months Ended June 30, 2016: | | | | | | | | | | | | | |
| Operating revenues | $ | 7,884 |
| | $ | 688 |
| | $ | (212 | ) | | $ | 8,360 |
| | $ | 172 |
| | $ | (81 | ) | | $ | 8,451 |
|
Segment net income (loss)(a)(c) | 1,059 |
| | 139 |
| | — |
| | 1,198 |
| | (94 | ) | | (7 | ) | | 1,097 |
|
| Total assets at June 30, 2016 | $ | 70,706 |
| | $ | 11,082 |
| | $ | (425 | ) | | $ | 81,363 |
| | $ | 10,505 |
| | $ | (995 | ) | | $ | 90,873 |
|
| Three Months Ended June 30, 2015: | | | | | | | | | | | | | |
| Operating revenues | $ | 4,077 |
| | $ | 337 |
| | $ | (90 | ) | | $ | 4,324 |
| | $ | 43 |
| | $ | (30 | ) | | $ | 4,337 |
|
Segment net income (loss)(a)(b) | 561 |
| | 46 |
| | — |
| | 607 |
| | 18 |
| | 4 |
| | 629 |
|
| Six Months Ended June 30, 2015: | | | | | | | | | | | | | |
| Operating revenues | $ | 8,025 |
| | $ | 684 |
| | $ | (213 | ) | | $ | 8,496 |
| | $ | 83 |
| | $ | (59 | ) | | $ | 8,520 |
|
Segment net income (loss)(a)(c) | 1,038 |
| | 79 |
| | — |
| | 1,117 |
| | 21 |
| | — |
| | 1,138 |
|
| Total assets at December 31, 2015 | $ | 69,052 |
| | $ | 8,905 |
| | $ | (397 | ) | | $ | 77,560 |
| | $ | 1,819 |
| | $ | (1,061 | ) | | $ | 78,318 |
|
| |
| (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 $81 million ($50 million after tax) and $23 million ($14 million after tax) for the three months ended June 30, 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 $134 million ($83 million after tax) and $32 million ($20 million after tax) for the six months ended June 30, 2016 and 2015, and June 30, 2014 includes a $32 million pre-tax charge ($20 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC.respectively. See Note (B) under "Integrated"Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" hereinEstimate" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)
Products and Services
| | | | | Electric Utilities' Revenues | | Electric Utilities' Revenues |
| Period | | Retail | | Wholesale | | Other | | Total | | Retail | | Wholesale | | Other | | Total |
| | | (in millions) | | (in millions) |
| Three Months Ended June 30, 2016 | | | $ | 3,748 |
| | $ | 446 |
| | $ | 185 |
| | $ | 4,379 |
|
| Three Months Ended June 30, 2015 | | $ | 3,714 |
| | $ | 448 |
| | $ | 162 |
| | $ | 4,324 |
| | 3,714 |
| | 448 |
| | 162 |
| | 4,324 |
|
| Three Months Ended June 30, 2014 | | 3,770 |
| | 515 |
| | 169 |
| | 4,454 |
| |
| | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2016 | | | $ | 7,124 |
| | $ | 842 |
| | $ | 394 |
| | $ | 8,360 |
|
| Six Months Ended June 30, 2015 | | $ | 7,256 |
| | $ | 915 |
| | $ | 325 |
| | $ | 8,496 |
| | 7,256 |
| | 915 |
| | 325 |
| | 8,496 |
|
| Six Months Ended June 30, 2014 | | 7,628 |
| | 1,119 |
| | 334 |
| | 9,081 |
| |
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. ThereExcept as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
Item 2. Unregistered SalesWith the completion of Equity Securitiesthe Merger, Southern Company now owns Southern Company Gas, a company whose subsidiaries own and Useoperate a natural gas business.
Southern Company Gas is an energy services holding company whose primary business is the distribution of Proceeds
(c) Issuer Purchasesnatural gas through natural gas distribution utilities. Southern Company Gas is involved in several other businesses that are mainly related and complementary to its primary business including: retail operations including the provision of Equity Securitiesnatural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, Southern Company is now subject to risks to which it was not previously subject and Southern Company stockholders may be adversely affected by these risks. These risks include the following:
Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs. Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.
|
| | | | | | | | | |
2015 | | Total Number ofSouthern 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 companies that supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies. Shares
Purchased (*)
| | Average Price
Paid Per Share
| | Total Number of Shares Purchased as Part of Publicly Announced Plans or
Programs (*)
| | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (*)
|
April 1 – April 30 | | — |
| | N/A | | N/A | | N/A |
May 1 – May 31 | | — |
| | N/A | | N/A | | N/A |
June 1 – June 30 | | — |
| | N/A | | N/A | | N/A |
Total | | — |
| | N/A | | N/A | | 17,400,634 |
| |
(*) | On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. There were no repurchases under this program in the second quarter 2015. As of June 30, 2015, Southern Company had repurchased a total of 2,599,366 shares under this program. |
195Southern 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 hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.
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 |
| | | | | |
| | | Southern Company |
| | | | |
| | (a)1 | - | By-lawsCertificate of Amendment to the Certificate of Incorporation of the Southern Company as amended effective May 27, 2015, and as presently in effect.26, 2016. (Designated in Form 8-K dated May 27, 2015,25, 2016, File No. 1-3526, as Exhibit 3.1.) |
| | | | | |
| | (a)2 | | By-Laws of the Southern Company, as amended effective May 25, 2016. (Designated in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.2.) |
| | | | |
|
| | | | |
| | | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | | |
| | | Southern Company |
| | | | | |
| | | (a)1 | - | EleventhTwelfth Supplemental Indenture to Senior Note Indenture, dated as of June 12, 2015,May 24, 2016, providing for the issuance of the Series 2015A 2.750%1.55% Senior Notes due June 15, 2020.2018. (Designated in Form 8-K dated June 9, 2015,May 19, 2016, File No. 1-3526, as Exhibit 4.2.4.2(a).) |
| | | | |
| | (a)2 | - | Thirteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 1.85% Senior Notes due 2019. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(b).) |
| | | | |
| | (a)3 | - | Fourteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.35% Senior Notes due 2021. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(c).) |
| | | | |
| | (a)4 | - | Fifteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.95% Senior Notes due 2023. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(d).) |
| | | | |
| | (a)5 | - | Sixteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 3.25% Senior Notes due 2026. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e).) |
| | | | |
| | (a)6 | - | Seventeenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.25% Senior Notes due 2036. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f).) |
| | | | |
| | (a)7 | - | Eighteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.40% Senior Notes due 2046. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g).) |
| | | | | |
| | | Southern Power |
| | | | | |
| | | (f)1 | - | SixthTenth Supplemental Indenture to Senior Note Indenture, dated as of MayJune 20, 2015,2016, providing for the issuance of the Series 2015A 1.500%2016A 1.000% Senior Notes due June 1, 2018.20, 2022. (Designated in Form 8-K dated May 14, 2015,June 13, 2016, File No. 333-98553,001-37803, as Exhibit 4.4(a).) |
| | | | | |
| | | (f)2 | - | SeventhEleventh Supplemental Indenture to Senior Note Indenture, dated as of MayJune 20, 2015,2016, providing for the issuance of the Series 2015B 2.375%2016B 1.850% Senior Notes due June 1, 2020.20, 2026. (Designated in Form 8-K dated May 14, 2015,June 13, 2016, File No. 333-98553,001-37803, as Exhibit 4.4(b).) |
| | | | |
| | | (10) Material Contracts |
| | | | |
| | | Southern Company |
| | | | | |
| # | * | (a)1 | - | Outside Directors Stock Plan for The Southern Company Supplemental Executive Retirement Plan, Amended and its Subsidiaries. (Designated in Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)Restated effective June 30, 2016. |
| | | | | |
| # | * | (a)2 | - | First Amendment to the Deferred Compensation Plan for Outside Directors of The Southern Company Supplemental Benefit Plan, Amended and Restated effective April 1, 2015.June 30, 2016. |
| | | | |
| | | Alabama Power |
| | | | | |
| # | * | (b)1 | - | First Amendment to the Deferred CompensationThe Southern Company Supplemental Executive Retirement Plan, for Outside Directors of Alabama Power Company,Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 2015.herein. |
| | | | |
| # | | (b)2 | - | Outside Directors Stock Plan for The Southern Company Supplemental Benefit Plan, Amended and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)Restated effective June 30, 2016. See Exhibit 10(a)2 herein. |
| | | | | |
| | | Georgia Power |
| | | |
| | * |
| # | | (c)1 | - | Amendment No. The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of June 4, 2015.herein. |
|
| | | | |
| | | | |
| # | | (c)2 | - | Outside Directors Stock Plan for The Southern Company Supplemental Benefit Plan, Amended and its Subsidiaries. (Designated in Southern Company's Definitive Proxy StatementRestated effective June 30, 2016. See Exhibit 10(a)2 herein. |
| | | | |
| * | (c)3 | - | Amendment No. 8 dated as of April 20, 2016, to Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc., as contractor, for Units 3&4 at the Vogtle Electric Generating Plant Site. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed April 10, 2015, File No. 1-3526, as Appendix A.them separately with the SEC.) |
| | | | | |
| | | Gulf Power |
| | | | | |
|
| | | | |
| # | * | (d)1 | - | First Amendment to the Deferred CompensationThe Southern Company Supplemental Executive Retirement Plan, for Outside Directors of Gulf Power Company,Amended and Restated effective April June 30, 2016. See Exhibit 10(a)1 2015.herein. |
| | | | |
| # | | (d)2 | - | Outside Directors Stock Plan for The Southern Company Supplemental Benefit Plan, Amended and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)Restated effective June 30, 2016. See Exhibit 10(a)2 herein. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| # | * | (e)1 | - | First Amendment to the Deferred CompensationThe Southern Company Supplemental Executive Retirement Plan, for Outside Directors of Mississippi Power Company,Amended and Restated effective April June 30, 2016. See Exhibit 10(a)1 2015.herein. |
| | | | |
| # | | (e)2 | - | Outside Directors Stock Plan for The Southern Company Supplemental Benefit Plan, Amended and its Subsidiaries. (Designated in Southern Company's Definitive Proxy Statement filed April 10, 2015, File No. 1-3526, as Appendix A.)Restated effective June 30, 2016. See Exhibit 10(a)2 herein. |
| | | | | |
| | | (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, 2014,2015, 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, 2014,2015, 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, 2014,2015, 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, 2014,2015, File No. 001-31737 as Exhibit 24(d).) |
| | | | |
| * | (d)2 | - | Power of Attorney for Xia Liu. |
| | | | | |
| | | Mississippi Power |
| | | | | |
| | | (e)1 | - | Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014,2015, 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, 2014,2015, File No. 333-98553 as Exhibit 24(f).1.) |
| | | | |
|
| | | | |
| | (f)2 | - | Power of Attorney for Joseph A. Miller. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)2.) |
| | | | | |
| | | (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. |
|
| | | | |
| | | | |
| | | (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. |
| | | | | |
| | | (101) XBRL – Related DocumentsInteractive 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.
|
| | | |
| | | 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: August 5, 20158, 2016
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.
|
| | | |
| | | 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: August 5, 20158, 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.
|
| | | |
| | | 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, Treasurer, and TreasurerCorporate Secretary |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: August 5, 20158, 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.
|
| | | |
| | | 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: August 5, 20158, 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.
|
| | | |
| | | MISSISSIPPI POWER COMPANY |
| | | | |
| By | | G. Edison Holland, Jr.Anthony L. Wilson |
| | | Chairman, President and Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
| By | | Moses H. Feagin |
| | | Vice President, Treasurer, and Chief Financial Officer, and Treasurer |
| | | (Principal Financial Officer) |
| | | | |
| By | | /s/Melissa K. Caen | |
| | | (Melissa K. Caen, Attorney-in-fact) | |
Date: August 5, 20158, 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.
|
| | | |
| | | SOUTHERN POWER COMPANY |
| | | | |
| By | | Oscar C. Harper IVJoseph 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: August 5, 20158, 2016